Guanidine- or guanidinium-containing compounds for treatment of subterranean formations

ABSTRACT

Various embodiments disclosed relate to guanidine- or guanidinium-containing clay or shale stabilizers for treatment of subterranean formations. In various embodiments, the present invention provides a method of treating a subterranean formation that can include placing a composition including a clay or shale stabilizer including at least one of a substituted guanidine group and a substituted guanidinium group in a subterranean formation.

BACKGROUND

Swelling clays can be a major mechanism of formation damage due to lossof mobility of hydrocarbon fluids in the formation. When clays encounterforeign water, they can swell, causing a loss of permeability. Theswelling can cause portions of the clay and adjacent fines to becomemobile within the production stream and, too frequently, encounterconstrictions in capillaries, where they can bridge off the capillariesand severely diminish the flow rate of hydrocarbons to the wellbore.Sometimes the loss of permeability observed is due to clay swellingwithout migration, but often clay swelling is accompanied by migrationof clay and other fines. Non-swelling clays may also respond to theforeign water and begin to migrate.

Shale is a fine-grained, fissile, detrital sedimentary rock formed byconsolidation of clay- and silt-sized particles into thin, relativelyimpermeable layers. Some shales encountered during subterraneanoperations can be sensitive to water, due in part to clay content andthe ionic composition of the clay. Such shales, also known as heaving orsloughing shales, can have a tendency to degrade, such as swell orcrack, upon contact with various downhole fluids, such as drillingfluids and fracturing fluids. The complications associated with shaledegradation during drilling may substantially increase the time and costof drilling. The degradation of shales in a borehole can render theborehole walls unstable. The heaving shale material can slough and caveinto the borehole. Degradation of the shale can interrupt circulation ofthe drilling fluid and cause greater friction between the drill stringand the wellbore. Sloughing of shale material into the borehole cancause the drill stem to become stuck and can enlarge the borehole, withthe result that large subterranean cavities are formed. The degradationof the shale may interfere with attempts to maintain the integrity ofdrilled cuttings traveling up the well bore until such time as thecuttings can be removed by solids control equipment located at thesurface. Degradation of drilled cuttings prior to their removal at thesurface may prolong drilling time because shale particles traveling upthe well bore can break up into smaller and smaller particles, which canexpose new surface area of the shale particles to the drilling fluid andlead to further absorption of water and degradation. Where sloughingoccurs while the drilling bit is being changed at the surface, theborehole fills up and must be cleared before drilling can proceed. Theheaving shale material taken up into the drilling fluid can adverselyaffect the viscosity characteristics of the drilling fluid to the pointwhere the fluid must be chemically treated to reduce the viscositythereof or it must be diluted followed by the addition of weighingmaterial to maintain a given mud weight.

Using oil-based fluids instead of aqueous-based fluids is one method ofinhibiting clay swelling and shale degradation. However, oil-basedfluids are often environmentally undesirable because they may be toxic.Accordingly, environmental regulations enacted by numerous countrieshave curtailed the use of oil-based fluids. Another method is to useclay or shale stabilizers. However, many clay or shale stabilizers areexpensive and are environmentally undesirable due to toxicity or lack ofbiodegradability, and can cause damage to subterranean formations.

BRIEF DESCRIPTION OF THE FIGURES

The drawings illustrate generally, by way of example, but not by way oflimitation, various embodiments discussed in the present document.

FIG. 1 illustrates a drilling assembly, in accordance with variousembodiments.

FIG. 2 illustrates a system or apparatus for delivering a composition toa subterranean formation, in accordance with various embodiments.

DETAILED DESCRIPTION OF THE INVENTION

Reference will now be made in detail to certain embodiments of thedisclosed subject matter, examples of which are illustrated in part inthe accompanying drawings. While the disclosed subject matter will bedescribed in conjunction with the enumerated claims, it will beunderstood that the exemplified subject matter is not intended to limitthe claims to the disclosed subject matter.

Values expressed in a range format should be interpreted in a flexiblemanner to include not only the numerical values explicitly recited asthe limits of the range, but also to include all the individualnumerical values or sub-ranges encompassed within that range as if eachnumerical value and sub-range is explicitly recited. For example, arange of “about 0.1% to about 5%” or “about 0.1% to 5%” should beinterpreted to include not just about 0.1% to about 5%, but also theindividual values (e.g., 1%, 2%, 3%, and 4%) and the sub-ranges (e.g.,0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the indicated range.The statement “about X to Y” has the same meaning as “about X to aboutY,” unless indicated otherwise. Likewise, the statement “about X, Y, orabout Z” has the same meaning as “about X, about Y, or about Z,” unlessindicated otherwise.

In this document, the terms “a,” “an,” or “the” are used to include oneor more than one unless the context clearly dictates otherwise. The term“or” is used to refer to a nonexclusive “or” unless otherwise indicated.The statement “at least one of A and B” has the same meaning as “A, B,or A and B.” In addition, it is to be understood that the phraseology orterminology employed herein, and not otherwise defined, is for thepurpose of description only and not of limitation. Any use of sectionheadings is intended to aid reading of the document and is not to beinterpreted as limiting; information that is relevant to a sectionheading may occur within or outside of that particular section.Furthermore, all publications, patents, and patent documents referred toin this document are incorporated by reference herein in their entirety,as though individually incorporated by reference. In the event ofinconsistent usages between this document and those documents soincorporated by reference, the usage in the incorporated referenceshould be considered supplementary to that of this document; forirreconcilable inconsistencies, the usage in this document controls.

In the methods of manufacturing described herein, the acts can becarried out in any order without departing from the principles of theinvention, except when a temporal or operational sequence is explicitlyrecited. Furthermore, specified acts can be carried out concurrentlyunless explicit claim language recites that they be carried outseparately. For example, a claimed act of doing X and a claimed act ofdoing Y can be conducted simultaneously within a single operation, andthe resulting process will fall within the literal scope of the claimedprocess.

Selected substituents within the compounds described herein are presentto a recursive degree. In this context, “recursive substituent” meansthat a substituent may recite another instance of itself or of anothersubstituent that itself recites the first substituent. Recursivesubstituents are an intended aspect of the disclosed subject matter.Because of the recursive nature of such substituents, theoretically, alarge number may be present in any given claim. One of ordinary skill inthe art of organic chemistry understands that the total number of suchsubstituents is reasonably limited by the desired properties of thecompound intended. Such properties include, by way of example and notlimitation, physical properties such as molecular weight, solubility,and practical properties such as ease of synthesis. Recursivesubstituents can call back on themselves any suitable number of times,such as about 1 time, about 2 times, 3, 4, 5, 6, 7, 8, 9, 10, 15, 20,30, 50, 100, 200, 300, 400, 500, 750, 1000, 1500, 2000, 3000, 4000,5000, 10,000, 15,000, 20,000, 30,000, 50,000, 100,000, 200,000, 500,000,750,000, or about 1,000,000 times or more.

The term “about” as used herein can allow for a degree of variability ina value or range, for example, within 10%, within 5%, or within 1% of astated value or of a stated limit of a range.

The term “substantially” as used herein refers to a majority of, ormostly, as in at least about 50%, 60%, 70%, 80%, 90%, 95%, 96%, 97%,98%, 99%, 99.5%, 99.9%, 99.99%, or at least about 99.999% or more.

The term “organic group” as used herein refers to but is not limited toany carbon-containing functional group. For example, anoxygen-containing group such as an alkoxy group, aryloxy group,aralkyloxy group, oxo(carbonyl) group, a carboxyl group including acarboxylic acid, carboxylate, and a carboxylate ester; asulfur-containing group such as an alkyl and aryl sulfide group; andother heteroatom-containing groups. Non-limiting examples of organicgroups include OR, OOR, OC(O)N(R)₂, CN, CF₃, OCF₃, R, C(O),methylenedioxy, ethylenedioxy, N(R)₂, SR, SOR, SO₂R, SO₂N(R)₂, SO₃R,C(O)R, C(O)C(O)R, C(O)CH₂C(O)R, C(S)R, C(O)OR, OC(O)R, C(O)N(R)₂,OC(O)N(R)₂, C(S)N(R)₂, (CH₂)₀₋₂N(R)C(O)R, (CH₂)₀₋₂N(R)N(R)₂,N(R)N(R)C(O)R, N(R)N(R)C(O)OR, N(R)N(R)CON(R)₂, N(R)SO₂R, N(R)SO₂N(R)₂,N(R)C(O)OR, N(R)C(O)R, N(R)C(S)R, N(R)C(O)N(R)₂, N(R)C(S)N(R)₂,N(COR)COR, N(OR)R, C(═NH)N(R)₂, C(O)N(OR)R, or C(═NOR)R, wherein R canbe hydrogen (in examples that include other carbon atoms) or acarbon-based moiety, and wherein the carbon-based moiety can itself befurther substituted.

The term “substituted” as used herein refers to an organic group asdefined herein or molecule in which one or more hydrogen atoms containedtherein are replaced by one or more non-hydrogen atoms. The term“functional group” or “substituent” as used herein refers to a groupthat can be or is substituted onto a molecule or onto an organic group.Examples of substituents or functional groups include, but are notlimited to, a halogen (e.g., F, Cl, Br, and I); an oxygen atom in groupssuch as hydroxy groups, alkoxy groups, aryloxy groups, aralkyloxygroups, oxo(carbonyl) groups, carboxyl groups including carboxylicacids, carboxylates, and carboxylate esters; a sulfur atom in groupssuch as thiol groups, alkyl and aryl sulfide groups, sulfoxide groups,sulfone groups, sulfonyl groups, and sulfonamide groups; a nitrogen atomin groups such as amines, hydroxyamines, nitriles, nitro groups,N-oxides, hydrazides, azides, and enamines; and other heteroatoms invarious other groups. Non-limiting examples of substituents J that canbe bonded to a substituted carbon (or other) atom include F, Cl, Br, I,OR, OC(O)N(R)₂, CN, NO, NO₂, ONO₂, azido, CF₃, OCF₃, R, O (oxo), S(thiono), C(O), S(O), methylenedioxy, ethylenedioxy, N(R)₂, SR, SOR,SO₂R, SO₂N(R)₂, SO₃R, C(O)R, C(O)C(O)R, C(O)CH₂C(O)R, C(S)R, C(O)OR,OC(O)R, C(O)N(R)₂, OC(O)N(R)₂, C(S)N(R)₂, (CH₂)₀₋₂N(R)C(O)R,(CH₂)₀₋₂N(R)N(R)₂, N(R)N(R)C(O)R, N(R)N(R)C(O)OR, N(R)N(R)CON(R)₂,N(R)SO₂R, N(R)SO₂N(R)₂, N(R)C(O)OR, N(R)C(O)R, N(R)C(S)R, N(R)C(O)N(R)₂,N(R)C(S)N(R)₂, N(COR)COR, N(OR)R, C(═NH)N(R)₂, C(O)N(OR)R, or C(═NOR)R,wherein R can be hydrogen or a carbon-based moiety, and wherein thecarbon-based moiety can itself be further substituted; for example,wherein R can be hydrogen, alkyl, acyl, cycloalkyl, aryl, aralkyl,heterocyclyl, heteroaryl, or heteroarylalkyl, wherein any alkyl, acyl,cycloalkyl, aryl, aralkyl, heterocyclyl, heteroaryl, or heteroarylalkylor R can be independently mono- or multi-substituted with J; or whereintwo R groups bonded to a nitrogen atom or to adjacent nitrogen atoms cantogether with the nitrogen atom or atoms form a heterocyclyl, which canbe mono- or independently multi-substituted with J.

The term “alkyl” as used herein refers to straight chain and branchedalkyl groups and cycloalkyl groups having from 1 to 40 carbon atoms, 1to about 20 carbon atoms, 1 to 12 carbons or, in some embodiments, from1 to 8 carbon atoms. Examples of straight chain alkyl groups includethose with from 1 to 8 carbon atoms such as methyl, ethyl, n-propyl,n-butyl, n-pentyl, n-hexyl, n-heptyl, and n-octyl groups. Examples ofbranched alkyl groups include, but are not limited to, isopropyl,iso-butyl, sec-butyl, t-butyl, neopentyl, isopentyl, and2,2-dimethylpropyl groups. As used herein, the term “alkyl” encompassesn-alkyl, isoalkyl, and anteisoalkyl groups as well as other branchedchain forms of alkyl. Representative substituted alkyl groups can besubstituted one or more times with any of the groups listed herein, forexample, amino, hydroxy, cyano, carboxy, nitro, thio, alkoxy, andhalogen groups.

The term “alkenyl” as used herein refers to straight and branched chainand cyclic alkyl groups as defined herein, except that at least onedouble bond exists between two carbon atoms. Thus, alkenyl groups havefrom 2 to 40 carbon atoms, or 2 to about 20 carbon atoms, or 2 to 12carbons or, in some embodiments, from 2 to 8 carbon atoms. Examplesinclude, but are not limited to vinyl, —CH═CH(CH₃), —CH═C(CH₃)₂,—C(CH₃)═CH₂, —C(CH₃)═CH(CH₃), —C(CH₂CH₃)═CH₂, cyclohexenyl,cyclopentenyl, cyclohexadienyl, butadienyl, pentadienyl, and hexadienylamong others.

The term “alkynyl” as used herein refers to straight and branched chainalkyl groups, except that at least one triple bond exists between twocarbon atoms. Thus, alkynyl groups have from 2 to 40 carbon atoms, 2 toabout 20 carbon atoms, or from 2 to 12 carbons or, in some embodiments,from 2 to 8 carbon atoms. Examples include, but are not limited to—C≡CH, —C≡C(CH₃), —C≡C(CH₂CH₃), —CH₂C≡CH, —CH₂C≡C(CH₃), and—CH₂C≡C(CH₂CH₃) among others.

The term “acyl” as used herein refers to a group containing a carbonylmoiety wherein the group is bonded via the carbonyl carbon atom. Thecarbonyl carbon atom is also bonded to another carbon atom, which can bepart of an alkyl, aryl, aralkyl cycloalkyl, cycloalkylalkyl,heterocyclyl, heterocyclylalkyl, heteroaryl, heteroarylalkyl group orthe like. In the special case wherein the carbonyl carbon atom is bondedto a hydrogen, the group is a “formyl” group, an acyl group as the termis defined herein. An acyl group can include 0 to about 12-20 or 12-40additional carbon atoms bonded to the carbonyl group. An acyl group caninclude double or triple bonds within the meaning herein. An acryloylgroup is an example of an acyl group. An acyl group can also includeheteroatoms within the meaning here. A nicotinoyl group(pyridyl-3-carbonyl) is an example of an acyl group within the meaningherein. Other examples include acetyl, benzoyl, phenylacetyl,pyridylacetyl, cinnamoyl, and acryloyl groups and the like. When thegroup containing the carbon atom that is bonded to the carbonyl carbonatom contains a halogen, the group is termed a “haloacyl” group. Anexample is a trifluoroacetyl group.

The term “cycloalkyl” as used herein refers to cyclic alkyl groups suchas, but not limited to, cyclopropyl, cyclobutyl, cyclopentyl,cyclohexyl, cycloheptyl, and cyclooctyl groups. In some embodiments, thecycloalkyl group can have 3 to about 8-12 ring members, whereas in otherembodiments the number of ring carbon atoms range from 3 to 4, 5, 6, or7. Cycloalkyl groups further include polycyclic cycloalkyl groups suchas, but not limited to, norbornyl, adamantyl, bornyl, camphenyl,isocamphenyl, and carenyl groups, and fused rings such as, but notlimited to, decalinyl, and the like. Cycloalkyl groups also includerings that are substituted with straight or branched chain alkyl groupsas defined herein. Representative substituted cycloalkyl groups can bemono-substituted or substituted more than once, such as, but not limitedto, 2,2-, 2,3-, 2,4-2,5- or 2,6-disubstituted cyclohexyl groups ormono-, di- or tri-substituted norbornyl or cycloheptyl groups, which canbe substituted with, for example, amino, hydroxy, cyano, carboxy, nitro,thio, alkoxy, and halogen groups. The term “cycloalkenyl” alone or incombination denotes a cyclic alkenyl group.

The term “aryl” as used herein refers to cyclic aromatic hydrocarbonsthat do not contain heteroatoms in the ring. Thus aryl groups include,but are not limited to, phenyl, azulenyl, heptalenyl, biphenyl,indacenyl, fluorenyl, phenanthrenyl, triphenylenyl, pyrenyl,naphthacenyl, chrysenyl, biphenylenyl, anthracenyl, and naphthyl groups.In some embodiments, aryl groups contain about 6 to about 14 carbons inthe ring portions of the groups. Aryl groups can be unsubstituted orsubstituted, as defined herein. Representative substituted aryl groupscan be mono-substituted or substituted more than once, such as, but notlimited to, 2-, 3-, 4-, 5-, or 6-substituted phenyl or 2-8 substitutednaphthyl groups, which can be substituted with carbon or non-carbongroups such as those listed herein.

The term “aralkyl” as used herein refers to alkyl groups as definedherein in which a hydrogen or carbon bond of an alkyl group is replacedwith a bond to an aryl group as defined herein. Representative aralkylgroups include benzyl and phenylethyl groups and fused(cycloalkylaryl)alkyl groups such as 4-ethyl-indanyl. Aralkenyl groupsare alkenyl groups as defined herein in which a hydrogen or carbon bondof an alkyl group is replaced with a bond to an aryl group as definedherein.

The term “heterocyclyl” as used herein refers to aromatic andnon-aromatic ring compounds containing three or more ring members, ofwhich one or more is a heteroatom such as, but not limited to, N, O, andS. Thus, a heterocyclyl can be a cycloheteroalkyl, or a heteroaryl, orif polycyclic, any combination thereof. In some embodiments,heterocyclyl groups include 3 to about 20 ring members, whereas othersuch groups have 3 to about 15 ring members. A heterocyclyl groupdesignated as a C₂-heterocyclyl can be a 5-ring with two carbon atomsand three heteroatoms, a 6-ring with two carbon atoms and fourheteroatoms and so forth. Likewise a C₄-heterocyclyl can be a 5-ringwith one heteroatom, a 6-ring with two heteroatoms, and so forth. Thenumber of carbon atoms plus the number of heteroatoms equals the totalnumber of ring atoms. A heterocyclyl ring can also include one or moredouble bonds. A heteroaryl ring is an embodiment of a heterocyclylgroup. The phrase “heterocyclyl group” includes fused ring speciesincluding those that include fused aromatic and non-aromatic groups.

The term “alkoxy” as used herein refers to an oxygen atom connected toan alkyl group, including a cycloalkyl group, as are defined herein.Examples of linear alkoxy groups include but are not limited to methoxy,ethoxy, propoxy, butoxy, pentyloxy, hexyloxy, and the like. Examples ofbranched alkoxy include but are not limited to isopropoxy, sec-butoxy,tert-butoxy, isopentyloxy, isohexyloxy, and the like. Examples of cyclicalkoxy include but are not limited to cyclopropyloxy, cyclobutyloxy,cyclopentyloxy, cyclohexyloxy, and the like. An alkoxy group can includeone to about 12-20 or about 12-40 carbon atoms bonded to the oxygenatom, and can further include double or triple bonds, and can alsoinclude heteroatoms. For example, an allyloxy group is an alkoxy groupwithin the meaning herein. A methoxyethoxy group is also an alkoxy groupwithin the meaning herein, as is a methylenedioxy group in a contextwhere two adjacent atoms of a structure are substituted therewith.

The term “amine” as used herein refers to primary, secondary, andtertiary amines having, e.g., the formula N(group)₃ wherein each groupcan independently be H or non-H, such as alkyl, aryl, and the like.Amines include but are not limited to R—NH₂, for example, alkylamines,arylamines, alkylarylamines; R₂NH wherein each R is independentlyselected, such as dialkylamines, diarylamines, aralkylamines,heterocyclylamines and the like; and R₃N wherein each R is independentlyselected, such as trialkylamines, dialkylarylamines, alkyldiarylamines,triarylamines, and the like. The term “amine” also includes ammoniumions as used herein.

The term “amino group” as used herein refers to a substituent of theform —NH₂, —NHR, —NR₂, —NR₃ ⁺, wherein each R is independently selected,and protonated forms of each, except for —NR₃ ⁺, which cannot beprotonated. Accordingly, any compound substituted with an amino groupcan be viewed as an amine. An “amino group” within the meaning hereincan be a primary, secondary, tertiary, or quaternary amino group. An“alkylamino” group includes a monoalkylamino, dialkylamino, andtrialkylamino group.

The terms “halo,” “halogen,” or “halide” group, as used herein, bythemselves or as part of another substituent, mean, unless otherwisestated, a fluorine, chlorine, bromine, or iodine atom.

The term “haloalkyl” group, as used herein, includes mono-halo alkylgroups, poly-halo alkyl groups wherein all halo atoms can be the same ordifferent, and per-halo alkyl groups, wherein all hydrogen atoms arereplaced by halogen atoms, such as fluoro. Examples of haloalkyl includetrifluoromethyl, 1,1-dichloroethyl, 1,2-dichloroethyl,1,3-dibromo-3,3-difluoropropyl, perfluorobutyl, and the like.

The term “hydrocarbon” as used herein refers to a functional group ormolecule that includes carbon and hydrogen atoms. The term can alsorefer to a functional group or molecule that normally includes bothcarbon and hydrogen atoms but wherein all the hydrogen atoms aresubstituted with other functional groups.

As used herein, the term “hydrocarbyl” refers to a functional groupderived from a straight chain, branched, or cyclic hydrocarbon, and canbe alkyl, alkenyl, alkynyl, aryl, cycloalkyl, acyl, or any combinationthereof.

The term “solvent” as used herein refers to a liquid that can dissolve asolid, liquid, or gas. Nonlimiting examples of solvents are silicones,organic compounds, water, alcohols, ionic liquids, and supercriticalfluids.

The term “number-average molecular weight” as used herein refers to theordinary arithmetic mean of the molecular weight of individual moleculesin a sample. It is defined as the total weight of all molecules in asample divided by the total number of molecules in the sample.Experimentally, the number-average molecular weight (M_(n)) isdetermined by analyzing a sample divided into molecular weight fractionsof species i having n_(i) molecules of molecular weight M_(i) throughthe formula M_(n)=ΓM_(i)n_(i)/Σn_(i). The number-average molecularweight can be measured by a variety of well-known methods including gelpermeation chromatography, spectroscopic end group analysis, andosmometry. If unspecified, molecular weights of polymers given hereinare number-average molecular weights.

The term “weight-average molecular weight” as used herein refers toM_(w), which is equal to ΣM_(i) ²n_(i)/ΣM_(i)n_(i), where n_(i) is thenumber of molecules of molecular weight M_(i). In various examples, theweight-average molecular weight can be determined using lightscattering, small angle neutron scattering, X-ray scattering, andsedimentation velocity.

The term “room temperature” as used herein refers to a temperature ofabout 15° C. to 28° C.

The term “standard temperature and pressure” as used herein refers to20° C. and 101 kPa.

As used herein, “degree of polymerization” is the number of repeatingunits in a polymer.

As used herein, the term “polymer” refers to a molecule having at leastone repeating unit and can include copolymers.

The term “copolymer” as used herein refers to a polymer that includes atleast two different repeating units. A copolymer can include anysuitable number of repeating units.

The term “downhole” as used herein refers to under the surface of theearth, such as a location within or fluidly connected to a wellbore.

As used herein, the term “drilling fluid” refers to fluids, slurries, ormuds used in drilling operations downhole, such as during the formationof the wellbore.

As used herein, the term “stimulation fluid” refers to fluids orslurries used downhole during stimulation activities of the well thatcan increase the production of a well, including perforation activities.In some examples, a stimulation fluid can include a fracturing fluid oran acidizing fluid.

As used herein, the term “clean-up fluid” refers to fluids or slurriesused downhole during clean-up activities of the well, such as anytreatment to remove material obstructing the flow of desired materialfrom the subterranean formation. In one example, a clean-up fluid can bean acidification treatment to remove material formed by one or moreperforation treatments. In another example, a clean-up fluid can be usedto remove a filter cake.

As used herein, the term “fracturing fluid” refers to fluids or slurriesused downhole during fracturing operations.

As used herein, the term “spotting fluid” refers to fluids or slurriesused downhole during spotting operations, and can be any fluid designedfor localized treatment of a downhole region. In one example, a spottingfluid can include a lost circulation material for treatment of aspecific section of the wellbore, such as to seal off fractures in thewellbore and prevent sag. In another example, a spotting fluid caninclude a water control material. In some examples, a spotting fluid canbe designed to free a stuck piece of drilling or extraction equipment,can reduce torque and drag with drilling lubricants, preventdifferential sticking, promote wellbore stability, and can help tocontrol mud weight.

As used herein, the term “completion fluid” refers to fluids or slurriesused downhole during the completion phase of a well, including cementingcompositions.

As used herein, the term “remedial treatment fluid” refers to fluids orslurries used downhole for remedial treatment of a well. Remedialtreatments can include treatments designed to increase or maintain theproduction rate of a well, such as stimulation or clean-up treatments.

As used herein, the term “abandonment fluid” refers to fluids orslurries used downhole during or preceding the abandonment phase of awell.

As used herein, the term “acidizing fluid” refers to fluids or slurriesused downhole during acidizing treatments. In one example, an acidizingfluid is used in a clean-up operation to remove material obstructing theflow of desired material, such as material formed during a perforationoperation. In some examples, an acidizing fluid can be used for damageremoval.

As used herein, the term “cementing fluid” refers to fluids or slurriesused during cementing operations of a well. For example, a cementingfluid can include an aqueous mixture including at least one of cementand cement kiln dust. In another example, a cementing fluid can includea curable resinous material such as a polymer that is in an at leastpartially uncured state.

As used herein, the term “water control material” refers to a solid orliquid material that interacts with aqueous material downhole, such thathydrophobic material can more easily travel to the surface and such thathydrophilic material (including water) can less easily travel to thesurface. A water control material can be used to treat a well to causethe proportion of water produced to decrease and to cause the proportionof hydrocarbons produced to increase, such as by selectively bindingtogether material between water-producing subterranean formations andthe wellbore while still allowing hydrocarbon-producing formations tomaintain output.

As used herein, the term “packer fluid” refers to fluids or slurriesthat can be placed in the annular region of a well between tubing andouter casing above a packer. In various examples, the packer fluid canprovide hydrostatic pressure in order to lower differential pressureacross the sealing element, lower differential pressure on the wellboreand casing to prevent collapse, and protect metals and elastomers fromcorrosion.

As used herein, the term “fluid” refers to liquids and gels, unlessotherwise indicated.

As used herein, the term “subterranean material” or “subterraneanformation” refers to any material under the surface of the earth,including under the surface of the bottom of the ocean. For example, asubterranean formation or material can be any section of a wellbore andany section of a subterranean petroleum- or water-producing formation orregion in fluid contact with the wellbore. Placing a material in asubterranean formation can include contacting the material with anysection of a wellbore or with any subterranean region in fluid contacttherewith. Subterranean materials can include any materials placed intothe wellbore such as cement, drill shafts, liners, tubing, or screens;placing a material in a subterranean formation can include contactingwith such subterranean materials. In some examples, a subterraneanformation or material can be any below-ground region that can produceliquid or gaseous petroleum materials, water, or any sectionbelow-ground in fluid contact therewith. For example, a subterraneanformation or material can be at least one of an area desired to befractured, a fracture or an area surrounding a fracture, and a flowpathway or an area surrounding a flow pathway, wherein a fracture or aflow pathway can be optionally fluidly connected to a subterraneanpetroleum- or water-producing region, directly or through one or morefractures or flow pathways.

As used herein, “treatment of a subterranean formation” can include anyactivity directed to extraction of water or petroleum materials from asubterranean petroleum- or water-producing formation or region, forexample, including drilling, stimulation, hydraulic fracturing,clean-up, acidizing, completion, cementing, remedial treatment,abandonment, and the like.

As used herein, a “flow pathway” downhole can include any suitablesubterranean flow pathway through which two subterranean locations arein fluid connection. The flow pathway can be sufficient for petroleum orwater to flow from one subterranean location to the wellbore orvice-versa. A flow pathway can include at least one of a hydraulicfracture, and a fluid connection across a screen, across gravel pack,across proppant, including across resin-bonded proppant or proppantdeposited in a fracture, and across sand. A flow pathway can include anatural subterranean passageway through which fluids can flow. In someembodiments, a flow pathway can be a water source and can include water.In some embodiments, a flow pathway can be a petroleum source and caninclude petroleum. In some embodiments, a flow pathway can be sufficientto divert from a wellbore, fracture, or flow pathway connected theretoat least one of water, a downhole fluid, or a produced hydrocarbon.

As used herein, a “carrier fluid” refers to any suitable fluid forsuspending, dissolving, mixing, or emulsifying with one or morematerials to form a composition. For example, the carrier fluid can beat least one of crude oil, dipropylene glycol methyl ether, dipropyleneglycol dimethyl ether, dipropylene glycol methyl ether, dipropyleneglycol dimethyl ether, dimethyl formamide, diethylene glycol methylether, ethylene glycol butyl ether, diethylene glycol butyl ether,butylglycidyl ether, propylene carbonate, D-limonene, a C₂-C₄₀ fattyacid C₁-C₁₀ alkyl ester (e.g., a fatty acid methyl ester),tetrahydrofurfuryl methacrylate, tetrahydrofurfuryl acrylate, 2-butoxyethanol, butyl acetate, butyl lactate, furfuryl acetate, dimethylsulfoxide, dimethyl formamide, a petroleum distillation product offraction (e.g., diesel, kerosene, napthas, and the like) mineral oil, ahydrocarbon oil, a hydrocarbon including an aromatic carbon-carbon bond(e.g., benzene, toluene), a hydrocarbon including an alpha olefin,xylenes, an ionic liquid, methyl ethyl ketone, an ester of oxalic,maleic or succinic acid, methanol, ethanol, propanol (iso- or normal-),butyl alcohol (iso-, tert-, or normal-), an aliphatic hydrocarbon (e.g.,cyclohexanone, hexane), water, brine, produced water, flowback water,brackish water, and sea water. The fluid can form about 0.001 wt % toabout 99.999 wt % of a composition, or a mixture including the same, orabout 0.001 wt % or less, 0.01 wt %, 0.1, 1, 2, 3, 4, 5, 6, 8, 10, 15,20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, 96, 97,98, 99, 99.9, 99.99, or about 99.999 wt % or more.

As used herein, a “shale stabilizer” is a material that slows orprevents the mechanical or chemical disaggregation of shale.

As used herein, a “clay stabilizer” is a material that slows or preventsthe mechanical or chemical disaggregation of clay.

The polymers described herein can terminate in any suitable way. In someembodiments, the polymers can terminate with an end group that isindependently chosen from a suitable polymerization initiator, —H, —OH,a substituted or unsubstituted (C₁-C₂₀)hydrocarbyl (e.g., (C₁-C₁₀)alkylor (C₆-C₂₀)aryl) at least one of interrupted with 0, 1, 2, or 3 groupsindependently substituted from —O—, substituted or unsubstituted —NH—,and —S—, a poly(substituted or unsubstituted (C₁-C₂₀)hydrocarbyloxy),and a poly(substituted or unsubstituted (C₁-C₂₀)hydrocarbylamino).

In various embodiments, the present invention provides a method oftreating a subterranean formation. The method includes placing acomposition including a clay or shale stabilizer in a subterraneanformation. The clay stabilizer or shale stabilizer includes at least oneof a substituted guanidine group and a substituted guanidinium group.

In various embodiments, the present invention provides a method oftreating a subterranean formation. The method includes placing adrilling fluid, fracturing fluid, cementing fluid, completion fluid,logging fluid, spotting fluid, or a packer fluid in a subterraneanformation. The drilling fluid, fracturing fluid, cementing fluid,completion fluid, logging fluid, spotting fluid, or packer fluidincludes a clay or shale stabilizer having the following structure

The variable R⁷ is selected from the group consisting of —OH, —OR⁸,—[O⁻]Y⁺, and —O⁻. The variable R⁸ is a (C₁-C₅₀)hydrocarbyl. The variableY⁺ is a counterion. The clay or shale stabilizer is about 0.001 wt % toabout 10 wt % of the drilling fluid, fracturing fluid, cementing fluid,completion fluid, logging fluid, spotting fluid, or the packer fluid.

In various embodiments, the present invention provides a method oftreating a subterranean formation. The method includes placing acomposition including a clay or shale stabilizer in a subterraneanformation. The clay or shale stabilizer includes at least one of anunsubstituted guanidine and an unsubstituted guanidinium. The guanidineand guanidinium are free of complexation with polyvalent metals.

In various embodiments, the present invention provides a systemincluding a composition including a clay or shale stabilizer includingat least one of a substituted guanidine group and a substitutedguanidinium group. The system also includes a subterranean formationincluding the composition therein.

In various embodiments, the present invention provides a composition fortreatment of a subterranean formation. The composition includes a clayor shale stabilizer including at least one of a substituted guanidinegroup and a substituted guanidinium group.

In various embodiments, the present invention provides a drilling fluid,fracturing fluid, cementing fluid, completion fluid, logging fluid,spotting fluid, or a packer fluid for treatment of a subterraneanformation. The composition includes a clay or shale stabilizer havingthe following structure

The variable R⁷ is selected from the group consisting of —OH, —OR⁸,—[O⁻]Y⁺, and —O⁻. The variable R⁸ is a (C₁-C₅₀)hydrocarbyl. The variableY⁺ is a counterion. The clay or shale stabilizer is about 0.001 wt % toabout 10 wt % of the drilling fluid, fracturing fluid, cementing fluid,completion fluid, logging fluid, spotting fluid, or the packer fluid.

In various embodiments, the present invention provides a method ofpreparing a composition for treatment of a subterranean formation. Themethod includes forming a composition including a clay or shalestabilizer including at least one of a substituted guanidine group and asubstituted guanidinium group.

Various embodiments of the present invention provide certain advantagesover other methods, composition, and systems for stabilization of clayor shale. For example, in some embodiments, unlike other clay or shaleinhibitors, the clay or shale stabilizer can be naturally derived, suchas from arginine, a common amino acid. In some embodiments, unlike otherclay or shale inhibitors, the clay or shale stabilizer can be readilybiodegradable. In some embodiments, the clay or shale stabilizer canhave less or no toxicity as compared to other clay or shale inhibitors.In various embodiments, the clay or shale stabilizer can stabilize orinhibit clay or shale disaggregation more effectively than other clay orshale inhibitors. In various embodiments, the amount of clay or shalestabilizer needed can be less costly to effect a given amount ofstabilization of clay or shale than the amount of another clay or shaleinhibitor needed to effect the same amount of stabilization.

Method of Treatment of a Subterranean Formation.

In some embodiments, the present invention provides a method of treatinga subterranean formation. The method includes placing a compositionincluding a clay or shale stabilizer including at least one of asubstituted guanidine group and a substituted guanidinium group in asubterranean formation. The composition can include a clay stabilizerthat is not a shale stabilizer, a shale stabilizer that is not a claystabilizer, or a stabilizer that is both a clay stabilizer and a shalestabilizer. The composition can include one or more clay stabilizers orshale stabilizers having at least one of a substituted guanidine groupand a substituted guanidinium group. The method can include obtaining orproviding the composition. The obtaining or providing of the compositioncan occur at any suitable time and at any suitable location. Theobtaining or providing of the composition can occur above the surface.The obtaining or providing of the composition can occur in thesubterranean formation (e.g., downhole). The placing of the compositionin the subterranean formation can include contacting the composition andany suitable part of the subterranean formation, or contacting thecomposition and a subterranean material, such as any suitablesubterranean material. The subterranean formation can be any suitablesubterranean formation.

In some examples, the placing of the composition in the subterraneanformation includes contacting the composition with or placing thecomposition in at least one of a fracture, at least a part of an areasurrounding a fracture, a flow pathway, an area surrounding a flowpathway, and an area desired to be fractured. The placing of thecomposition in the subterranean formation can be any suitable placingand can include any suitable contacting between the subterraneanformation and the composition. The placing of the composition in thesubterranean formation can include using the composition as a drillingfluid or as a cementing fluid.

The method can include hydraulic fracturing, such as a method ofhydraulic fracturing to generate a fracture or flow pathway. The placingof the composition in the subterranean formation or the contacting ofthe subterranean formation and the hydraulic fracturing can occur at anytime with respect to one another; for example, the hydraulic fracturingcan occur at least one of before, during, and after the contacting orplacing. In some embodiments, the contacting or placing occurs duringthe hydraulic fracturing, such as during any suitable stage of thehydraulic fracturing, such as during at least one of a pre-pad stage(e.g., during injection of water with no proppant, and additionallyoptionally mid- to low-strength acid), a pad stage (e.g., duringinjection of fluid only with no proppant, with some viscosifier, such asto begin to break into an area and initiate fractures to producesufficient penetration and width to allow proppant-laden later stages toenter), or a slurry stage of the fracturing (e.g., viscous fluid withproppant). The method can include performing a stimulation treatment atleast one of before, during, and after placing the composition in thesubterranean formation in the fracture, flow pathway, or areasurrounding the same. The stimulation treatment can be, for example, atleast one of perforating, acidizing, injecting of cleaning fluids,propellant stimulation, and hydraulic fracturing. In some embodiments,the stimulation treatment at least partially generates a fracture orflow pathway where the composition is placed or contacted, or thecomposition is placed or contacted to an area surrounding the generatedfracture or flow pathway.

In some embodiments, the method can be a method of drilling,stimulation, fracturing, spotting, clean-up, completion, remedialtreatment, applying a pill, acidizing, cementing, or a combinationthereof, wherein the composition can be or can include a drilling fluid,stimulation fluid, a fracturing fluid, a spotting fluid, a clean-upfluid, a completion fluid, a remedial treatment fluid, a pill, anacidization fluid, a cementing fluid, respectively.

In some embodiments, the composition can include carrier fluid. Thecarrier fluid can be any suitable fluid or combination of fluids, suchas an aqueous fluid, an organic fluid, or an oil. The carrier fluid canbe any suitable proportion of the composition, such as about 0.000.1 wt% to 99.999.9 wt % of the composition, or about 0.01 wt % to about 99.99wt %, about 0.1 wt % to about 99.9 wt %, or about 20 wt % to about 90 wt%, about 50 wt % to about 99.999 wt %, or about 0.000.1 wt % or less, orabout 0.001 wt %, 0.01, 0.1, 1, 2, 3, 4, 5, 10, 15, 20, 30, 40, 50, 60,70, 80, 85, 90, 91, 92, 93, 94, 95, 96, 97, 98, 99, 99.9, 99.99, 99.999wt %, or about 99.999.9 wt % or more of the composition can be thecarrier fluid.

In some embodiments, the composition can include an aqueous liquid. Theaqueous liquid can be any suitable aqueous liquid, such as at least oneof water, brine, produced water, flowback water, brackish water, and seawater. In some embodiments, the aqueous liquid can include at least oneof an aqueous drilling fluid, aqueous fracturing fluid, aqueousdiverting fluid, and an aqueous fluid loss control fluid. In someembodiments, the aqueous liquid can be the aqueous phase of an emulsion(e.g., the composition can include an emulsion having as the aqueousphase the aqueous liquid). The aqueous liquid can be any suitableproportion of the composition, such that the composition can be used asdescribed herein. For example, about 0.000.1 wt % to 99.999.9 wt % ofthe composition can be the aqueous liquid, or about 0.01 wt % to about99.99 wt %, about 0.1 wt % to about 99.9 wt %, or about 20 wt % to about90 wt %, or about 0.000.1 wt % or less, or about 0.001 wt %, 0.01, 0.1,1, 2, 3, 4, 5, 10, 15, 20, 30, 40, 50, 60, 70, 80, 85, 90, 91, 92, 93,94, 95, 96, 97, 98, 99, 99.9, 99.99, 99.999 wt %, or about 99.999.9 wt %or more of the composition can be the aqueous liquid.

The aqueous liquid can be a salt water. The salt can be any suitablesalt, such as at least one of NaBr, CaCl₂, CaBr₂, ZnBr₂, KCl, NaCl, amagnesium salt, a bromide salt, a formate salt, an acetate salt, and anitrate salt. The aqueous liquid can have any suitable total dissolvedsolids level (e.g., wherein the dissolved solids correspond to dissolvedsalts), such as about 1,000 mg/L to about 250,000 mg/L, or about 1,000mg/L or less, or about 5,000 mg/L, 10,000, 15,000, 20,000, 25,000,30,000, 40,000, 50,000, 75,000, 100,000, 125,000, 150,000, 175,000,200,000, 225,000, or about 250,000 mg/L or more. The aqueous liquid canhave any suitable salt concentration, such as about 1,000 ppm to about300,000 ppm, or about 1,000 ppm to about 150,000 ppm, or about 1,000 ppmor less, or about 5,000 ppm, 10,000, 15,000, 20,000, 25,000, 30,000,40,000, 50,000, 75,000, 100,000, 125,000, 150,000, 175,000, 200,000,225,000, 250,000, 275,000, or about 300,000 ppm or more. In someexamples, the aqueous liquid can have a concentration of at least one ofNaBr, CaCl₂, CaBr₂, ZnBr₂, KCl, and NaCl of about 0.1% w/v to about 20%w/v, or about 0.1% w/v or less, or about 0.5% w/v, 1, 2, 3, 4, 5, 6, 7,8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25,26, 27, 28, 29, or about 30% w/v or more.

The composition can be oil-based (e.g., over 50 wt % oil or organicfluids) or water-based (e.g., over 50 wt % aqueous fluids). In someembodiments, the composition can be an emulsion. The emulsion can be anaqueous-external emulsion or an oil-external emulsion. The clay or shalestabilizer can be at least partially dissolved in the water-phase of anemulsion, at least partially dissolved in an oil-phase of an emulsion,or a combination thereof.

Clay or Shale Stabilizer.

The composition can include one clay or shale stabilizer, or more thanone clay or shale stabilizer. The stabilizer can be a clay stabilizer, ashale stabilizer, or a clay and shale stabilizer. Any suitableproportion of the composition can be the clay or shale stabilizer, suchas about 0.000.1 wt % to 99.999.9 wt % of the composition, or about 0.01wt % to about 99.99 wt %, about 0.001 wt % to about 99.9 wt %, or about0.001 wt % to about 10 wt %, or about 0.000.1 wt % or less, or about0.000,001 wt %, 0.000,1, 0.001, 0.01, 0.1, 1, 2, 3, 4, 5, 6, 7, 8, 9,10, 15, 20, 30, 40, 50, 60, 70, 80, 85, 90, 91, 92, 93, 94, 95, 96, 97,98, 99, 99.9, 99.99, 99.999 wt %, or about 99.999.9 wt % or more of thecomposition. In some embodiments, the clay or shale stabilizer can be orcan be derivable from arginine, such as L-arginine, such as via at leastone reaction selected from alkoxylation, alkalyation,alkylcarboxylation, alkylesterification, halogenation, oxidation, andamidification. In various embodiments, the solubility of the clay orshale stabilizer can be tuned, such as by using long-chain esters orsubstituents to enhance oil or organic solubility, or by using acids,salts, or guanidinium groups to enhance water solubility. In variousembodiments, the clay or shale stabilizer can operate in any suitableway, such as by substituting for other ions in a clay lattice which makeit more prone to swelling.

In some embodiments, the clay or shale stabilizer can be anunsubstituted guanidine or guanidinium having the structure:

The variable X⁻ is counterion. The guanidine and guanidinium can be freeof complexation with polyvalent metals. Complexation can be at least oneinteraction with the metal chosen from at least one of ionic, covalent,dipole-dipole, London dispersion force, and hydrogen bonding, whereinthe interaction is of sufficient strength that a stable complex betweenthe guanidine or guanidinium and the metal is formed. In someembodiments, the guanidine and guanidinium are free of complexation withmetals, such as aluminum. In some embodiments, the guanidine andguanidinium are free of complexation with aluminum hydroxide, sodiumaluminate, aluminum sulfate, and aluminum phosphate.

In some embodiments, the clay or shale stabilizer can be a compound thatincludes a substituted guanidine group or a substituted guanidiniumgroup. The stabilizer can include one or more substituted guanidinegroups, one or more substituted guanidinium groups, or a combinationthereof. In some embodiments, the clay or shale stabilizer has thestructure:

The variables R¹, R², R³, R⁴, R⁵, and R⁶ can each be independentlyselected from —H, halogen, an organic group, and substituted orunsubstituted (C₁-C₃₀)hydrocarbyl interrupted by 0, 1, 2, or 3 of atleast one of —O—, —S—, and substituted or unsubstituted —NH—, or atleast one pair of R¹, R², R³, R⁴, R⁵, and R⁶ can together form asubstituted or unsubstituted (C₂-C₂₀)hydrocarbylene such that at leasttwo of the nitrogen atoms in the clay or shale stabilizer are part of aheterocycle including the substituted or unsubstituted(C₂-C₂₀)hydrocarbylene. Optionally, at least one of R¹, R², R³, R⁴, R⁵,and R⁶ can be bonded to at least one R¹, R², R³, R⁴, R⁵, and R⁶ on adifferent guanidine or guanidinium group in the same clay or shalestabilizer. The guanidine or guanidinium is substituted, such that atleast one of R¹, R², R³, R⁴, and R⁵ is not —H. The variable X⁻ is acounterion. In some examples, the variable R⁶ can be —H. A guanidinegroup can distribute charge between the nitrogen atoms, and can thus berepresented by the resonance structures:

A guanidinium group can distribute charge between the nitrogen atoms,and can thus be represented by the resonance structures:

The variable X⁻ can be any suitable anionic counterion. The variable X⁻can be selected from the group consisting of fluoride, chloride, iodide,bromide, nitrate, hydrogen sulfate, dihydrogen phosphate, bicarbonate,nitrite, perchlorate, iodate, chlorate, bromate, chlorite, hypochlorite,hypobromite, cyanide, amide, cyanate, hydroxide, permanganate, acetate,formate, oxide, sulfide, nitride, arsenate, phosphate, arsenite,hydrogen phosphate, sulfate, thiosulfate, sulfite, carbonate, chromate,dichromate, peroxide, and oxalate.

The variables R², R³, R⁴, R⁵, and R⁶ can each be independently selectedfrom —H and substituted or unsubstituted (C₁-C₁₅)alkyl. The variablesR², R³, R⁴, R⁵, and R⁶ can be each independently selected from —H andsubstituted or unsubstituted (C₁-C₅)alkyl. The variables R², R³, R⁴, R⁵,and R⁶ can each be —H.

In some embodiments, at least one pair of R¹, R², R³, R⁴, R⁵, and R⁶ cantogether form a (C₂-C₅)alkylene such that at least two of the nitrogenatoms in the clay or shale stabilizer are part of a heterocycleincluding the (C₂-C₅)alkylene. At least one pair of R¹, R², R³, R⁴, R⁵,and R⁶ together form a (C₃)alkylene such that at least two of thenitrogen atoms in the clay or shale stabilizer are part of a heterocycleincluding the (C₃)alkylene. In some embodiments, the clay or shalestabilizer is 1,5,7-triazabicyclo[4.4.0]dec-5-ene, having the structure:

The clay or shale stabilizer can be a polymer, such as a polymer havingthe substituted guanidine group or substituted guanidinium group aspendant groups on the backbone of the polymer. The polymer can have anysuitable degree of polymerization, and can include any suitableproportion of repeating groups that include a pendant guanidine orguanidinium group. In some embodiments of a polymeric clay or shalestabilizer, at least one of R¹, R², R³, R⁴, R⁵, and R⁶ can be bonded toat least one R¹, R², R³, R⁴, R⁵, and R⁶ on a different guanidine orguanidinium group in the same clay or shale stabilizer.

In some embodiments, the clay or shale stabilizer includes two or moreof the guanidine or guanidinium groups connected to one another via a(C₁-C₃₀)hydrocarbyl linker. For example, the clay or shale stabilizercan have the structure:

The variables R², R³, R⁴, R⁵, and R⁶ can be each independently selectedfrom —H, halogen, an organic group, and substituted or unsubstituted(C₁-C₃₀)hydrocarbyl interrupted by 0, 1, 2, or 3 of at least one of —O—,—S—, and substituted or unsubstituted —NH—, or at least one pair of R²,R³, R⁴, R⁵, and R⁶ together can form a substituted or unsubstituted(C₂-C₂₀)hydrocarbylene such that at least two of the nitrogen atoms inthe clay or shale stabilizer are part of a heterocycle including thesubstituted or unsubstituted (C₂-C₂₀)hydrocarbylene. Optionally, atleast one of R², R³, R⁴, R⁵, and R⁶ can be bonded to at least one R²,R³, R⁴, R⁵, and R⁶ on a different guanidine or guanidinium group in thesame clay or shale stabilizer. The variable X⁻ is a counterion. Thevariable L³ is a substituted or unsubstituted (C₁-C₃₀)hydrocarbylinterrupted by 0, 1, 2, or 3 of at least one of —O—, —S—, andsubstituted or unsubstituted —NH—. The variable L³ can be (C₂-C₂₀)alkyl.The clay or shale stabilizer can be 1,6-hexamethylene-bis-guanidine or1,6-hexamethylene-bis-cyanoguanidine.

In some embodiments, R¹ can be -L¹-C(O)R⁷. In some embodiments, the clayor shale stabilizer has the structure:

The variable L¹ can be selected from the group consisting of a bond, asubstituted or unsubstituted (C₁-C₃₀)hydrocarbylene interrupted by 0, 1,2, or 3 of at least one of —O—, —S—, and substituted or unsubstituted—NH—. Optionally, L¹ can include a bond to at least one R¹, R², R³, R⁴,R⁵, and R⁶ on a different guanidine or guanidinium group in the sameclay or shale stabilizer. The variable L¹ can be a(C₁-C₃₀)hydrocarbylene interrupted by 0, 1, 2, or 3 of at least one of—O—, —S—, and substituted or unsubstituted —NH— and including at leastone —NH₂ substituent. The variable L¹ can be a (C₁-C₁₅)alkyleneincluding at least one —NH₂ substituent. The variable L¹ can be abutylene including at least one —NH₂ substituent. The variable L¹ can be—(CH₂)₃—CH(NH₂)—. The variable R⁷ can be selected from the groupconsisting of —OH, —OR⁸, —O⁻Y⁺, —O⁻, and a bond to at least one R¹, R²,R³, R⁴, R⁵, and R⁶ on a different guanidine or guanidinium group in thesame clay or shale stabilizer. The variable R⁸ can be a substituted orunsubstituted (C₁-C₅₀)hydrocarbyl interrupted by 0, 1, 2, or 3 of atleast one of —O—, —S—, and substituted or unsubstituted —NH—. Thevariable R⁸ can be a (C₁-C₅₀)alkyl. The variable R⁸ can be a(C₁-C₁₅)alkyl. The variable R⁸ can be a (C₁-C₅)alkyl. The variable R⁸can be ethyl. The variable Y⁺ is a counterion, such as any suitablecationic counterion, such as selected from the group consisting of Na⁺,K⁺, Li⁺, H⁺, NH₄ ⁺, Ca²⁺, Mg²⁺, Zn²⁺, and Al³⁺.

In some embodiments, the clay or shale stabilizer can be a polymerincluding repeating units having the structure:

In some embodiments, the clay or shale stabilizer has the structure:

The variable L² can be selected from the group consisting of a bond anda substituted or unsubstituted (C₁-C₂₈)hydrocarbylene interrupted by 0,1, 2, or 3 of at least one of —O—, —S—, and substituted or unsubstituted—NH—. The variable L² can be a (C₁-C₁₅)alkylene. The variable L² can bea propylene. The variable L² can be —(CH₂)₃—.

The clay or shale stabilizer can be a polymer including repeating unitshaving the structure:

In some embodiments, the clay or shale stabilizer has the structure:

or a salt thereof,

or a salt thereof, or

The clay or shale stabilizer can be a polymer including repeating unitshaving the structure:

In some embodiments, the clay or shale stabilizer is L or D (or anysuitable mixture of L and D) arginine or a salt thereof, a guanidiniumform of the arginine or a salt thereof, or is a zwitterionic form of thearginine with a guanidinium and a carboxylate ion. In some embodiments,the clay or shale stabilizer is a polyarginine, or polymer includingarginine repeating units (e.g., any suitable protein including anarginine unit). The clay or shale stabilizer can have the structure:

or a salt thereof,

or a salt thereof, or

The clay or shale stabilizer can be a polymer including repeating unitshaving the structure:

In some embodiments, the clay or shale stabilizer is L-arginine or asalt thereof, a guanidinium form of L-arginine or a salt thereof, or isa zwitterionic form of L-arginine with a guanidinium and a carboxylateion. The clay or shale stabilizer can have the structure:

or a salt thereof,

or a salt thereof, or

The clay or shale stabilizer can be a polymer including repeating unitshaving the structure:

In some embodiments, the clay or shale stabilizer is an ester of L or D(or any suitable mixture of L and D) arginine, or an ester of aguanidinium form of the arginine. The clay or shale stabilizer can havethe structure:

The variable R⁸ can be a substituted or unsubstituted(C₁-C₅₀)hydrocarbyl interrupted by 0, 1, 2, or 3 of at least one of —O—,—S—, and substituted or unsubstituted —NH—. The variable R⁸ can be a(C₁-C₅₀)alkyl. The variable R⁸ can be a (C₁-C₁₅)alkyl. The variable R⁸can be a (C₁-C₅)alkyl. The variable R⁸ can be ethyl.

In some embodiments, the clay or shale stabilizer is an ester ofL-arginine, or an ester of a guanidinium form of L-arginine. The clay orshale stabilizer can have the structure:

The variable R⁸ can be a substituted or unsubstituted(C₁-C₅₀)hydrocarbyl interrupted by 0, 1, 2, or 3 of at least one of —O—,—S—, and substituted or unsubstituted —NH—. The variable R⁸ can be a(C₁-C₅₀)alkyl. The variable R⁸ can be a (C₁-C₁₅)alkyl. The variable R⁸can be a (C₁-C₅)alkyl. The variable R⁸ can be ethyl.Other Components.

The composition including the clay or shale stabilizer, or a mixtureincluding the composition, can include any suitable additional componentin any suitable proportion, such that the composition, or mixtureincluding the same, can be used as described herein.

In some embodiments, the composition includes one or more second clay orshale stabilizers. The second clay or shale stabilizer can be anysuitable clay or shale stabilizer. In various embodiments, the secondclay or shale stabilizer can be a substituted or unsubstituted amine(e.g., triethylamine), potassium chloride, a crosslinkedpolyvinylpyrrolidone, an inorganic phosphate (e.g., as described in U.S.Pat. No. 4,605,068), a polyalkoxy diamine or a salt thereof (e.g., asdescribed in U.S. Pat. Nos. 6,484,821; 6,609,578; 6,247,543; and U.S.Patent Publication No. 20030106718), choline or a choline derivative(e.g., as described in U.S. Pat. No. 5,908,814), an oligomethylenediamine or a salt thereof (e.g., as described in U.S. Pat. No. 5,771,971and U.S. Patent Publication No. 20020155956), an addition product ofcarboxymethyl cellulose and an organic amine (e.g., as described in WO2006/013595), 1,2-cyclohexanediamine or a salt thereof (e.g., asdescribed in WO 2006/013597), a salt of a phosphoric acid ester of anoxyalkylated polyol (e.g., as described in WO 2006/013597), acombination of a partially hydrolyzed acrylic copolymer potassiumchloride and polyanionic cellulose (e.g., as described in U.S. Pat. No.4,664,818), a quaternary ammonium compound (e.g., as described in U.S.Pat. Nos. 5,197,544 and 5,380,706), a polymer based on dialkylaminoalkyl methacrylate (e.g., as described in U.S. Pat. No. 7,091,159),an aqueous solution containing a polymer with hydrophilic andhydrophobic groups (e.g., as described in U.S. Pat. No. 5,728,653), anda reaction product of a polyhydroxyalkane and an alkylene oxide (e.g.,as described in U.S. Pat. No. 6,544,933), and PERFORMATROL® shalestabilizer. In some embodiments, the second clay or shale stabilizer canbe about 0.000.1 wt % to about 50 wt % of the composition, about 0.000.1wt % to about 10 wt %, about 0.004 wt % to about 0.01 wt % of thecomposition, or about 0.000.1 wt % or less, 0.000.5 wt %, 0.001, 0.005,0.01, 0.05, 0.1, 0.5, 1, 2, 3, 4, 5, 6, 7, 8, 9, or about 10 wt % ormore of the composition.

In some embodiments, the composition includes one or more viscosifiers.The viscosifier can be any suitable viscosifier. The viscosifier canaffect the viscosity of the composition or a solvent that contacts thecomposition at any suitable time and location. In some embodiments, theviscosifier provides an increased viscosity at least one of beforeinjection into the subterranean formation, at the time of injection intothe subterranean formation, during travel through a tubular disposed ina borehole, once the composition reaches a particular subterraneanlocation, or some period of time after the composition reaches aparticular subterranean location. In some embodiments, the viscosifiercan be about 0.000.1 wt % to about 10 wt % of the composition, about0.004 wt % to about 0.01 wt % of the composition, or about 0.000.1 wt %or less, 0.000.5 wt %, 0.001, 0.005, 0.01, 0.05, 0.1, 0.5, 1, 2, 3, 4,5, 6, 7, 8, 9, or about 10 wt % or more of the composition.

The viscosifier can include at least one of a substituted orunsubstituted polysaccharide, and a substituted or unsubstitutedpolyalkene (e.g., a polyethylene, wherein the ethylene unit issubstituted or unsubstituted, derived from the corresponding substitutedor unsubstituted ethene), wherein the polysaccharide or polyalkene iscrosslinked or uncrosslinked. The viscosifier can include a polymerincluding at least one repeating unit derived from a monomer selectedfrom the group consisting of ethylene glycol, acrylamide, vinyl acetate,2-acrylamidomethylpropane sulfonic acid or its salts,trimethylammoniumethyl acrylate halide, and trimethylammoniumethylmethacrylate halide. The viscosifier can include a crosslinked gel or acrosslinkable gel. The viscosifier can include at least one of a linearpolysaccharide and a poly((C₂-C₁₀)alkene), wherein the (C₂-C₁₀)alkene issubstituted or unsubstituted. The viscosifier can include at least oneof poly(acrylic acid) or (C₁-C₅)alkyl esters thereof, poly(methacrylicacid) or (C₁-C₅)alkyl esters thereof, poly(vinyl acetate), poly(vinylalcohol), poly(ethylene glycol), poly(vinyl pyrrolidone),polyacrylamide, poly (hydroxyethyl methacrylate), alginate, chitosan,curdlan, dextran, emulsan, a galactoglucopolysaccharide, gellan,glucuronan, N-acetyl-glucosamine, N-acetyl-heparosan, hyaluronic acid,kefiran, lentinan, levan, mauran, pullulan, scleroglucan, schizophyllan,stewartan, succinoglycan, xanthan, diutan, welan, derivatized starch,tamarind, tragacanth, guar gum, derivatized guar (e.g., hydroxypropylguar, carboxy methyl guar, or carboxymethyl hydroxypropyl guar), gumghatti, gum arabic, locust bean gum, and derivatized cellulose (e.g.,carboxymethyl cellulose, hydroxyethyl cellulose, carboxymethylhydroxyethyl cellulose, hydroxypropyl cellulose, or methyl hydroxy ethylcellulose).

In some embodiments, the viscosifier can include at least one of apoly(vinyl alcohol) homopolymer, poly(vinyl alcohol) copolymer, acrosslinked poly(vinyl alcohol) homopolymer, and a crosslinkedpoly(vinyl alcohol) copolymer. The viscosifier can include a poly(vinylalcohol) copolymer or a crosslinked poly(vinyl alcohol) copolymerincluding at least one of a graft, linear, branched, block, and randomcopolymer of vinyl alcohol and at least one of a substituted orunsubstituted (C₂-C₅₀)hydrocarbyl having at least one aliphaticunsaturated C≡C bond therein, and a substituted or unsubstituted(C₂-C₅₀)alkene. The viscosifier can include a poly(vinyl alcohol)copolymer or a crosslinked poly(vinyl alcohol) copolymer including atleast one of a graft, linear, branched, block, and random copolymer ofvinyl alcohol and at least one of vinyl phosphonic acid, vinylidenediphosphonic acid, substituted or unsubstituted2-acrylamido-2-methylpropanesulfonic acid, a substituted orunsubstituted (C₁-C₂₀)alkenoic acid, propenoic acid, butenoic acid,pentenoic acid, hexenoic acid, octenoic acid, nonenoic acid, decenoicacid, acrylic acid, methacrylic acid, hydroxypropyl acrylic acid,acrylamide, fumaric acid, methacrylic acid, hydroxypropyl acrylic acid,vinyl phosphonic acid, vinylidene diphosphonic acid, itaconic acid,crotonic acid, mesoconic acid, citraconic acid, styrene sulfonic acid,allyl sulfonic acid, methallyl sulfonic acid, vinyl sulfonic acid, and asubstituted or unsubstituted (C₁-C₂₀)alkyl ester thereof. Theviscosifier can include a poly(vinyl alcohol) copolymer or a crosslinkedpoly(vinyl alcohol) copolymer including at least one of a graft, linear,branched, block, and random copolymer of vinyl alcohol and at least oneof vinyl acetate, vinyl propanoate, vinyl butanoate, vinyl pentanoate,vinyl hexanoate, vinyl 2-methyl butanoate, vinyl 3-ethylpentanoate, andvinyl 3-ethylhexanoate, maleic anhydride, a substituted or unsubstituted(C₁-C₂₀)alkenoic substituted or unsubstituted (C₁-C₂₀)alkanoicanhydride, a substituted or unsubstituted (C₁-C₂₀)alkenoic substitutedor unsubstituted (C₁-C₂₀)alkenoic anhydride, propenoic acid anhydride,butenoic acid anhydride, pentenoic acid anhydride, hexenoic acidanhydride, octenoic acid anhydride, nonenoic acid anhydride, decenoicacid anhydride, acrylic acid anhydride, fumaric acid anhydride,methacrylic acid anhydride, hydroxypropyl acrylic acid anhydride, vinylphosphonic acid anhydride, vinylidene diphosphonic acid anhydride,itaconic acid anhydride, crotonic acid anhydride, mesoconic acidanhydride, citraconic acid anhydride, styrene sulfonic acid anhydride,allyl sulfonic acid anhydride, methallyl sulfonic acid anhydride, vinylsulfonic acid anhydride, and an N—(C₁-C₁₀)alkenyl nitrogen containingsubstituted or unsubstituted (C₁-C₁₀)heterocycle. The viscosifier caninclude a poly(vinyl alcohol) copolymer or a crosslinked poly(vinylalcohol) copolymer including at least one of a graft, linear, branched,block, and random copolymer that includes apoly(vinylalcohol/acrylamide) copolymer, apoly(vinylalcohol/2-acrylamido-2-methylpropanesulfonic acid) copolymer,a poly (acrylamide/2-acrylamido-2-methylpropanesulfonic acid) copolymer,or a poly(vinylalcohol/N-vinylpyrrolidone) copolymer. The viscosifiercan include a crosslinked poly(vinyl alcohol) homopolymer or copolymerincluding a crosslinker including at least one of chromium, aluminum,antimony, zirconium, titanium, calcium, boron, iron, silicon, copper,zinc, magnesium, and an ion thereof. The viscosifier can include acrosslinked poly(vinyl alcohol) homopolymer or copolymer including acrosslinker including at least one of an aldehyde, an aldehyde-formingcompound, a carboxylic acid or an ester thereof, a sulfonic acid or anester thereof, a phosphonic acid or an ester thereof, an acid anhydride,and an epihalohydrin.

In various embodiments, the composition can include one or morecrosslinkers. The crosslinker can be any suitable crosslinker. In someexamples, the crosslinker can be incorporated in a crosslinkedviscosifier, and in other examples, the crosslinker can crosslink acrosslinkable material (e.g., downhole). The crosslinker can include atleast one of chromium, aluminum, antimony, zirconium, titanium, calcium,boron, iron, silicon, copper, zinc, magnesium, and an ion thereof. Thecrosslinker can include at least one of boric acid, borax, a borate, a(C₁-C₃₀)hydrocarbylboronic acid, a (C₁-C₃₀)hydrocarbyl ester of a(C₁-C₃₀)hydrocarbylboronic acid, a (C₁-C₃₀)hydrocarbylboronicacid-modified polyacrylamide, ferric chloride, disodium octaboratetetrahydrate, sodium metaborate, sodium diborate, sodium tetraborate,disodium tetraborate, a pentaborate, ulexite, colemanite, magnesiumoxide, zirconium lactate, zirconium triethanol amine, zirconium lactatetriethanolamine, zirconium carbonate, zirconium acetylacetonate,zirconium malate, zirconium citrate, zirconium diisopropylamine lactate,zirconium glycolate, zirconium triethanol amine glycolate, zirconiumlactate glycolate, titanium lactate, titanium malate, titanium citrate,titanium ammonium lactate, titanium triethanolamine, titaniumacetylacetonate, aluminum lactate, and aluminum citrate. In someembodiments, the crosslinker can be a (C₁-C₂₀)alkylenebiacrylamide(e.g., methylenebisacrylamide), a poly((C₁-C₂₀)alkenyl)-substitutedmono- or poly-(C₁-C₂₀)alkyl ether (e.g., pentaerythritol allyl ether),and a poly(C₂-C₂₀)alkenylbenzene (e.g., divinylbenzene). In someembodiments, the crosslinker can be at least one of alkyl diacrylate,ethylene glycol diacrylate, ethylene glycol dimethacrylate, polyethyleneglycol diacrylate, polyethylene glycol dimethacrylate, ethoxylatedbisphenol A diacrylate, ethoxylated bisphenol A dimethacrylate,ethoxylated trimethylol propane triacrylate, ethoxylated trimethylolpropane trimethacrylate, ethoxylated glyceryl triacrylate, ethoxylatedglyceryl trimethacrylate, ethoxylated pentaerythritol tetraacrylate,ethoxylated pentaerythritol tetramethacrylate, ethoxylateddipentaerythritol hexaacrylate, polyglyceryl monoethylene oxidepolyacrylate, polyglyceryl polyethylene glycol polyacrylate,dipentaerythritol hexaacrylate, dipentaerythritol hexamethacrylate,neopentyl glycol diacrylate, neopentyl glycol dimethacrylate,pentaerythritol triacrylate, pentaerythritol trimethacrylate,trimethylol propane triacrylate, trimethylol propane trimethacrylate,tricyclodecane dimethanol diacrylate, tricyclodecane dimethanoldimethacrylate, 1,6-hexanediol diacrylate, and 1,6-hexanedioldimethacrylate. The crosslinker can be about 0.000.01 wt % to about 5 wt% of the composition, about 0.001 wt % to about 0.01 wt %, or about0.000.01 wt % or less, or about 0.000.05 wt %, 0.000,1, 0.000,5, 0.001,0.005, 0.01, 0.05, 0.1, 0.5, 1, 2, 3, 4, or about 5 wt % or more.

In some embodiments, the composition can include one or more breakers.The breaker can be any suitable breaker, such that the surrounding fluid(e.g., a fracturing fluid) can be at least partially broken for morecomplete and more efficient recovery thereof, such as at the conclusionof the hydraulic fracturing treatment. In some embodiments, the breakercan be encapsulated or otherwise formulated to give a delayed-release ora time-release of the breaker, such that the surrounding liquid canremain viscous for a suitable amount of time prior to breaking. Thebreaker can be any suitable breaker; for example, the breaker can be acompound that includes a Na⁺, K⁺, Li⁺, NH₄ ⁺, Fe²⁺, Fe³⁺, Cu¹⁺, Cu²⁺,Ca²⁺, Mg²⁺, Zn²⁺, and an Al³⁺ salt of a chloride, fluoride, bromide,phosphate, or sulfate ion. In some examples, the breaker can be anoxidative breaker or an enzymatic breaker. An oxidative breaker can beat least one of a Na⁺, K⁺, Li⁺, NH₄₊, Fe²⁺, Fe³⁺, Cu¹⁺, Cu²⁺, Ca²⁺,Mg²⁺, Zn²⁺, and an Al³⁺ salt of a persulfate, percarbonate, perborate,peroxide, perphosphosphate, permanganate, chlorite, or hyporchloriteion. An enzymatic breaker can be at least one of an alpha or betaamylase, amyloglucosidase, oligoglucosidase, invertase, maltase,cellulase, hemi-cellulase, and mannanohydrolase. The breaker can beabout 0.001 wt % to about 30 wt % of the composition, or about 0.01 wt %to about 5 wt %, or about 0.001 wt % or less, or about 0.005 wt %, 0.01,0.05, 0.1, 0.5, 1, 2, 3, 4, 5, 6, 8, 10, 12, 14, 16, 18, 20, 22, 24, 26,28, or about 30 wt % or more.

The composition, or a mixture including the composition, can include anysuitable fluid. For example, the fluid can be at least one of crude oil,dipropylene glycol methyl ether, dipropylene glycol dimethyl ether,dipropylene glycol methyl ether, dipropylene glycol dimethyl ether,dimethyl formamide, diethylene glycol methyl ether, ethylene glycolbutyl ether, diethylene glycol butyl ether, butylglycidyl ether,propylene carbonate, D-limonene, a C₂-C₄₀ fatty acid C₁-C₁₀ alkyl ester(e.g., a fatty acid methyl ester), tetrahydrofurfuryl methacrylate,tetrahydrofurfuryl acrylate, 2-butoxy ethanol, butyl acetate, butyllactate, furfuryl acetate, dimethyl sulfoxide, dimethyl formamide, apetroleum distillation product of fraction (e.g., diesel, kerosene,napthas, and the like) mineral oil, a hydrocarbon oil, a hydrocarbonincluding an aromatic carbon-carbon bond (e.g., benzene, toluene), ahydrocarbon including an alpha olefin, xylenes, an ionic liquid, methylethyl ketone, an ester of oxalic, maleic or succinic acid, methanol,ethanol, propanol (iso- or normal-), butyl alcohol (iso-, tert-, ornormal-), an aliphatic hydrocarbon (e.g., cyclohexanone, hexane), water,brine, produced water, flowback water, brackish water, and sea water.The fluid can form about 0.001 wt % to about 99.999 wt % of thecomposition, or a mixture including the same, or about 0.001 wt % orless, 0.01 wt %, 0.1, 1, 2, 3, 4, 5, 6, 8, 10, 15, 20, 25, 30, 35, 40,45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, 96, 97, 98, 99, 99.9, 99.99,or about 99.999 wt % or more.

The composition including the clay or shale stabilizer can include anysuitable downhole fluid. The composition including the clay or shalestabilizer can be combined with any suitable downhole fluid before,during, or after the placement of the composition in the subterraneanformation or the contacting of the composition and the subterraneanmaterial. In some examples, the composition including the clay or shalestabilizer is combined with a downhole fluid above the surface, and thenthe combined composition is placed in a subterranean formation orcontacted with a subterranean material. In another example, thecomposition including the clay or shale stabilizer is injected into asubterranean formation to combine with a downhole fluid, and thecombined composition is contacted with a subterranean material or isconsidered to be placed in the subterranean formation. In variousexamples, at least one of prior to, during, and after the placement ofthe composition in the subterranean formation or contacting of thesubterranean material and the composition, the composition is used inthe subterranean formation (e.g., downhole), at least one of alone andin combination with other materials, as a drilling fluid, stimulationfluid, fracturing fluid, spotting fluid, clean-up fluid, completionfluid, remedial treatment fluid, abandonment fluid, pill, acidizingfluid, cementing fluid, packer fluid, or a combination thereof.

In various embodiments, the composition including the clay or shalestabilizer, or a mixture including the same, can include any suitabledownhole fluid, such as an aqueous or oil-based fluid including adrilling fluid, stimulation fluid, fracturing fluid, spotting fluid,clean-up fluid, completion fluid, remedial treatment fluid, abandonmentfluid, pill, acidizing fluid, cementing fluid, packer fluid, or acombination thereof. The placement of the composition in thesubterranean formation can include contacting the subterranean materialand the mixture. Any suitable weight percent of the composition or of amixture including the same that is placed in the subterranean formationor contacted with the subterranean material can be the downhole fluid,such as about 0.001 wt % to about 99.999 wt %, about 0.01 wt % to about99.99 wt %, about 0.1 wt % to about 99.9 wt %, about 20 wt % to about 90wt %, or about 0.001 wt % or less, or about 0.01 wt %, 0.1, 1, 2, 3, 4,5, 10, 15, 20, 30, 40, 50, 60, 70, 80, 85, 90, 91, 92, 93, 94, 95, 96,97, 98, 99, 99.9, 99.99 wt %, or about 99.999 wt % or more of thecomposition or mixture including the same.

In some embodiments, the composition, or a mixture including the same,can include any suitable amount of any suitable material used in adownhole fluid. For example, the composition or a mixture including thesame can include water, saline, aqueous base, acid, oil, organicsolvent, synthetic fluid oil phase, aqueous solution, alcohol or polyol,cellulose, starch, alkalinity control agents, acidity control agents,density control agents, density modifiers, emulsifiers, dispersants,polymeric stabilizers, crosslinking agents, polyacrylamide, a polymer orcombination of polymers, antioxidants, heat stabilizers, foam controlagents, solvents, diluents, plasticizer, filler or inorganic particle,pigment, dye, precipitating agent, rheology modifier, oil-wettingagents, set retarding additives, surfactants, gases, weight reducingadditives, heavy-weight additives, lost circulation materials,filtration control additives, salts (e.g., any suitable salt, such aspotassium salts such as potassium chloride, potassium bromide, potassiumformate; calcium salts such as calcium chloride, calcium bromide,calcium formate; cesium salts such as cesium chloride, cesium bromide,cesium formate, or a combination thereof), fibers, thixotropicadditives, breakers, crosslinkers, rheology modifiers, curingaccelerators, curing retarders, pH modifiers, chelating agents, scaleinhibitors, enzymes, resins, water control materials, oxidizers,markers, Portland cement, pozzolana cement, gypsum cement, high aluminacontent cement, slag cement, silica cement, fly ash, metakaolin, shale,zeolite, a crystalline silica compound, amorphous silica, hydratableclays, microspheres, lime, or a combination thereof. In variousembodiments, the composition or a mixture including the same can includeone or more additive components such as: COLDTROL®, ATC®, OMC 2™, andOMC 42™ thinner additives; RHEMOD™ viscosifier and suspension agent;TEMPERUS™ and VIS-PLUS® additives for providing temporary increasedviscosity; TAU-MOD™ viscosifying/suspension agent; ADAPTA®, DURATONE®HT, THERMO TONE™, BDF™-366, and BDF™-454 filtration control agents;LIQUITONE™ polymeric filtration agent and viscosifier; FACTANT™ emulsionstabilizer; LE SUPERMUL™, EZ MUL® NT, and FORTI-MUL® emulsifiers; DRILTREAT® oil wetting agent for heavy fluids; BARACARB® bridging agent;BAROID® weighting agent; BAROLIFT® hole sweeping agent; SWEEP-WATE®sweep weighting agent; BDF-508 rheology modifier; and GELTONE® IIorganophilic clay. In various embodiments, the composition or a mixtureincluding the same can include one or more additive components such as:X-TEND® II, PAC™-R, PAC™-L, LIQUI-VIS® EP, BRINEDRIL-VIS™, BARAZAN®,N-VIS®, and AQUAGEL® viscosifiers; THERMA-CHEK®, N-DRIL™, N-DRIL™ HTPLUS, IMPERMEX®, FILTERCHEK™, DEXTRID®, CARBONOX®, and BARANEX®filtration control agents; PERFORMATROL®, GEM™, EZ-MUD®, CLAY GRABBER®,CLAYSEAL®, CRYSTAL-DRIL®, and CLAY SYNC™ II shale stabilizers;NXS-LUBE™, EP MUDLUBE®, and DRIL-N-SLIDE™ lubricants; QUIK-THIN®,IRON-THIN™, and ENVIRO-THIN™ thinners; SOURSCAV™ scavenger; BARACOR®corrosion inhibitor; and WALL-NUT®, SWEEP-WATE®, STOPPIT™, PLUG-GIT®,BARACARB®, DUO-SQUEEZE®, BAROFIBRE™, STEELSEAL®, and HYDRO-PLUG® lostcirculation management materials. Any suitable proportion of thecomposition or mixture including the composition can include anyoptional component listed in this paragraph, such as about 0.001 wt % toabout 99.999 wt %, about 0.01 wt % to about 99.99 wt %, about 0.1 wt %to about 99.9 wt %, about 20 to about 90 wt %, or about 0.001 wt % orless, or about 0.01 wt %, 0.1, 1, 2, 3, 4, 5, 10, 15, 20, 30, 40, 50,60, 70, 80, 85, 90, 91, 92, 93, 94, 95, 96, 97, 98, 99, 99.9, 99.99 wt%, or about 99.999 wt % or more of the composition or mixture.

A drilling fluid, also known as a drilling mud or simply “mud,” is aspecially designed fluid that is circulated through a wellbore as thewellbore is being drilled to facilitate the drilling operation. Thedrilling fluid can be water-based or oil-based. The drilling fluid cancarry cuttings up from beneath and around the bit, transport them up theannulus, and allow their separation. Also, a drilling fluid can cool andlubricate the drill bit as well as reduce friction between the drillstring and the sides of the hole. The drilling fluid aids in support ofthe drill pipe and drill bit, and provides a hydrostatic head tomaintain the integrity of the wellbore walls and prevent well blowouts.Specific drilling fluid systems can be selected to optimize a drillingoperation in accordance with the characteristics of a particulargeological formation. The drilling fluid can be formulated to preventunwanted influxes of formation fluids from permeable rocks and also toform a thin, low permeability filter cake that temporarily seals pores,other openings, and formations penetrated by the bit. In water-baseddrilling fluids, solid particles are suspended in a water or brinesolution containing other components. Oils or other non-aqueous liquidscan be emulsified in the water or brine or at least partiallysolubilized (for less hydrophobic non-aqueous liquids), but water is thecontinuous phase. A drilling fluid can be present in the mixture withthe composition including the clay or shale stabilizer in any suitableamount, such as about 1 wt % or less, about 2 wt %, 3, 4, 5, 10, 15, 20,30, 40, 50, 60, 70, 80, 85, 90, 95, 96, 97, 98, 99, 99.9, 99.99, orabout 99.999 wt % or more of the mixture.

A water-based drilling fluid in embodiments of the present invention canbe any suitable water-based drilling fluid. In various embodiments, thedrilling fluid can include at least one of water (fresh or brine), asalt (e.g., calcium chloride, sodium chloride, potassium chloride,magnesium chloride, calcium bromide, sodium bromide, potassium bromide,calcium nitrate, sodium formate, potassium formate, cesium formate),aqueous base (e.g., sodium hydroxide or potassium hydroxide), alcohol orpolyol, cellulose, starches, alkalinity control agents, density controlagents such as a density modifier (e.g., barium sulfate), surfactants(e.g., betaines, alkali metal alkylene acetates, sultaines, ethercarboxylates), emulsifiers, dispersants, polymeric stabilizers,crosslinking agents, polyacrylamides, polymers or combinations ofpolymers, antioxidants, heat stabilizers, foam control agents, solvents,diluents, plasticizers, filler or inorganic particles (e.g., silica),pigments, dyes, precipitating agents (e.g., silicates or aluminumcomplexes), and rheology modifiers such as thickeners or viscosifiers(e.g., xanthan gum). Any ingredient listed in this paragraph can beeither present or not present in the mixture.

An oil-based drilling fluid or mud in embodiments of the presentinvention can be any suitable oil-based drilling fluid. In variousembodiments the drilling fluid can include at least one of an oil-basedfluid (or synthetic fluid), saline, aqueous solution, emulsifiers, otheragents or additives for suspension control, weight or density control,oil-wetting agents, fluid loss or filtration control agents, andrheology control agents. An oil-based or invert emulsion-based drillingfluid can include between about 10:90 to about 95:5, or about 50:50 toabout 95:5, by volume of oil phase to water phase. A substantially alloil mud includes about 100% liquid phase oil by volume (e.g.,substantially no internal aqueous phase).

A pill is a relatively small quantity (e.g., less than about 500 bbl, orless than about 200 bbl) of drilling fluid used to accomplish a specifictask that the regular drilling fluid cannot perform. For example, a pillcan be a high-viscosity pill to, for example, help lift cuttings out ofa vertical wellbore. In another example, a pill can be a freshwater pillto, for example, dissolve a salt formation. Another example is apipe-freeing pill to, for example, destroy filter cake and relievedifferential sticking forces. In another example, a pill is a lostcirculation material pill to, for example, plug a thief zone. A pill caninclude any component described herein as a component of a drillingfluid.

A cement fluid can include an aqueous mixture of at least one of cementand cement kiln dust. The composition including the clay or shalestabilizer can form a useful combination with cement or cement kilndust. The cement kiln dust can be any suitable cement kiln dust. Cementkiln dust can be formed during the manufacture of cement and can bepartially calcined kiln feed that is removed from the gas stream andcollected in a dust collector during a manufacturing process. Cementkiln dust can be advantageously utilized in a cost-effective mannersince kiln dust is often regarded as a low value waste product of thecement industry. Some embodiments of the cement fluid can include cementkiln dust but no cement, cement kiln dust and cement, or cement but nocement kiln dust. The cement can be any suitable cement. The cement canbe a hydraulic cement. A variety of cements can be utilized inaccordance with embodiments of the present invention; for example, thoseincluding calcium, aluminum, silicon, oxygen, iron, or sulfur, which canset and harden by reaction with water. Suitable cements can includePortland cements, pozzolana cements, gypsum cements, high aluminacontent cements, slag cements, silica cements, and combinations thereof.In some embodiments, the Portland cements that are suitable for use inembodiments of the present invention are classified as Classes A, C, H,and G cements according to the American Petroleum Institute, APISpecification for Materials and Testing for Well Cements, APISpecification 10, Fifth Ed., Jul. 1, 1990. A cement can be generallyincluded in the cementing fluid in an amount sufficient to provide thedesired compressive strength, density, or cost. In some embodiments, thehydraulic cement can be present in the cementing fluid in an amount inthe range of from 0 wt % to about 100 wt %, about 0 wt % to about 95 wt%, about 20 wt % to about 95 wt %, or about 50 wt % to about 90 wt %. Acement kiln dust can be present in an amount of at least about 0.01 wt%, or about 5 wt % to about 80 wt %, or about 10 wt % to about 50 wt %.

Optionally, other additives can be added to a cement or kilndust-containing composition of embodiments of the present invention asdeemed appropriate by one skilled in the art, with the benefit of thisdisclosure. Any optional ingredient listed in this paragraph can beeither present or not present in the composition. For example, thecomposition can include fly ash, metakaolin, shale, zeolite, setretarding additive, surfactant, a gas, accelerators, weight reducingadditives, heavy-weight additives, lost circulation materials,filtration control additives, dispersants, and combinations thereof. Insome examples, additives can include crystalline silica compounds,amorphous silica, salts, fibers, hydratable clays, microspheres,pozzolan lime, thixotropic additives, combinations thereof, and thelike.

In various embodiments, the composition or mixture can include aproppant, a resin-coated proppant, an encapsulated resin, or acombination thereof. A proppant is a material that keeps an inducedhydraulic fracture at least partially open during or after a fracturingtreatment. Proppants can be transported into the subterranean formation(e.g., downhole) to the fracture using fluid, such as fracturing fluidor another fluid. A higher-viscosity fluid can more effectivelytransport proppants to a desired location in a fracture, especiallylarger proppants, by more effectively keeping proppants in a suspendedstate within the fluid. Examples of proppants can include sand, gravel,glass beads, polymer beads, ground products from shells and seeds suchas walnut hulls, and manmade materials such as ceramic proppant,bauxite, tetrafluoroethylene materials (e.g., TEFLON™polytetrafluoroethylene), fruit pit materials, processed wood, compositeparticulates prepared from a binder and fine grade particulates such assilica, alumina, fumed silica, carbon black, graphite, mica, titaniumdioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron,fly ash, hollow glass microspheres, and solid glass, or mixturesthereof. In some embodiments, the proppant can have an average particlesize, wherein particle size is the largest dimension of a particle, ofabout 0.001 mm to about 3 mm, about 0.15 mm to about 2.5 mm, about 0.25mm to about 0.43 mm, about 0.43 mm to about 0.85 mm, about 0.85 mm toabout 1.18 mm, about 1.18 mm to about 1.70 mm, or about 1.70 to about2.36 mm. In some embodiments, the proppant can have a distribution ofparticle sizes clustering around multiple averages, such as one, two,three, or four different average particle sizes. The composition ormixture can include any suitable amount of proppant, such as about 0.01wt % to about 99.99 wt %, about 0.1 wt % to about 80 wt %, about 10 wt %to about 60 wt %, or about 0.01 wt % or less, or about 0.1 wt %, 1, 2,3, 4, 5, 10, 15, 20, 30, 40, 50, 60, 70, 80, 85, 90, 91, 92, 93, 94, 95,96, 97, 98, 99, about 99.9 wt %, or about 99.99 wt % or more.

The composition can include a payload material. The payload can bedeposited in any suitable subterranean location. The method can includeusing the composition to deposit a payload material into a subterraneanfracture. The subterranean fracture can be any suitable subterraneanfracture. In some embodiments, the method includes forming thesubterranean fracture; in other embodiments, the subterranean fractureis already formed. The payload material can be a proppant, or any othersuitable payload material, such as a resin-coated proppant, a curablematerial, an encapsulated resin, a resin, a Portland cement, a pozzolanacement, a gypsum cement, a high alumina content cement, a slag cement, asilica cement, a cementitous kiln dust, fly ash, metakaolin, shale,zeolite, a set retarding additive, a corrosion inhibitor, a surfactant,a gas, an accelerator, a weight reducing additive, a heavy-weightadditive, a lost circulation material, a filtration control additive, adispersant, a crystalline silica compound, an amorphous silica, a salt,a fiber, a hydratable clay, a microsphere, pozzolan lime, a thixotropicadditive, water, an aqueous base, an aqueous acid, an alcohol or polyol,a cellulose, a starch, an alkalinity control agent, an acidity controlagent, a density control agent, a density modifier, an emulsifier, apolymeric stabilizer, a crosslinking agent, a polyacrylamide, a polymeror combination of polymers, an antioxidant, a heat stabilizer, a foamcontrol agent, a solvent, a diluent, a plasticizer, a filler orinorganic particle, a pigment, a dye, a precipitating agent, a rheologymodifier, or a combination thereof.

Drilling Assembly.

In various embodiments, the composition including the clay or shalestabilizer disclosed herein can directly or indirectly affect one ormore components or pieces of equipment associated with the preparation,delivery, recapture, recycling, reuse, and/or disposal of the disclosedcomposition including the clay or shale stabilizer. For example, andwith reference to FIG. 1, the disclosed composition including the clayor shale stabilizer can directly or indirectly affect one or morecomponents or pieces of equipment associated with an exemplary wellboredrilling assembly 100, according to one or more embodiments. It shouldbe noted that while FIG. 1 generally depicts a land-based drillingassembly, those skilled in the art will readily recognize that theprinciples described herein are equally applicable to subsea drillingoperations that employ floating or sea-based platforms and rigs, withoutdeparting from the scope of the disclosure.

As illustrated, the drilling assembly 100 can include a drillingplatform 102 that supports a derrick 104 having a traveling block 106for raising and lowering a drill string 108. The drill string 108 caninclude drill pipe and coiled tubing, as generally known to thoseskilled in the art. A kelly 110 supports the drill string 108 as it islowered through a rotary table 112. A drill bit 114 is attached to thedistal end of the drill string 108 and is driven either by a downholemotor and/or via rotation of the drill string 108 from the well surface.As the bit 114 rotates, it creates a wellbore 116 that penetratesvarious subterranean formations 118.

A pump 120 (e.g., a mud pump) circulates drilling fluid 122 through afeed pipe 124 and to the kelly 110, which conveys the drilling fluid 122downhole through the interior of the drill string 108 and through one ormore orifices in the drill bit 114. The drilling fluid 122 is thencirculated back to the surface via an annulus 126 defined between thedrill string 108 and the walls of the wellbore 116. At the surface, therecirculated or spent drilling fluid 122 exits the annulus 126 and canbe conveyed to one or more fluid processing unit(s) 128 via aninterconnecting flow line 130. After passing through the fluidprocessing unit(s) 128, a “cleaned” drilling fluid 122 is deposited intoa nearby retention pit 132 (e.g., a mud pit). While illustrated as beingarranged at the outlet of the wellbore 116 via the annulus 126, thoseskilled in the art will readily appreciate that the fluid processingunit(s) 128 can be arranged at any other location in the drillingassembly 100 to facilitate its proper function, without departing fromthe scope of the disclosure.

The composition including the clay or shale stabilizer can be added tothe drilling fluid 122 via a mixing hopper 134 communicably coupled toor otherwise in fluid communication with the retention pit 132. Themixing hopper 134 can include mixers and related mixing equipment knownto those skilled in the art. In other embodiments, however, thecomposition including the clay or shale stabilizer can be added to thedrilling fluid 122 at any other location in the drilling assembly 100.In at least one embodiment, for example, there could be more than oneretention pit 132, such as multiple retention pits 132 in series.Moreover, the retention pit 132 can be representative of one or morefluid storage facilities and/or units where the composition includingthe clay or shale stabilizer can be stored, reconditioned, and/orregulated until added to the drilling fluid 122.

As mentioned above, the composition including the clay or shalestabilizer can directly or indirectly affect the components andequipment of the drilling assembly 100. For example, the compositionincluding the clay or shale stabilizer can directly or indirectly affectthe fluid processing unit(s) 128, which can include one or more of ashaker (e.g., shale shaker), a centrifuge, a hydrocyclone, a separator(including magnetic and electrical separators), a desilter, a desander,a separator, a filter (e.g., diatomaceous earth filters), a heatexchanger, or any fluid reclamation equipment. The fluid processingunit(s) 128 can further include one or more sensors, gauges, pumps,compressors, and the like used to store, monitor, regulate, and/orrecondition the composition including the clay or shale stabilizer.

The composition including the clay or shale stabilizer can directly orindirectly affect the pump 120, which representatively includes anyconduits, pipelines, trucks, tubulars, and/or pipes used to fluidicallyconvey the composition including the clay or shale stabilizer to thesubterranean formation, any pumps, compressors, or motors (e.g., topsideor downhole) used to drive the composition into motion, any valves orrelated joints used to regulate the pressure or flow rate of thecomposition, and any sensors (e.g., pressure, temperature, flow rate,and the like), gauges, and/or combinations thereof, and the like. Thecomposition including the clay or shale stabilizer can also directly orindirectly affect the mixing hopper 134 and the retention pit 132 andtheir assorted variations.

The composition including the clay or shale stabilizer can also directlyor indirectly affect the various downhole or subterranean equipment andtools that can come into contact with the composition including the clayor shale stabilizer such as the drill string 108, any floats, drillcollars, mud motors, downhole motors, and/or pumps associated with thedrill string 108, and any measurement while drilling (MWD)/logging whiledrilling (LWD) tools and related telemetry equipment, sensors, ordistributed sensors associated with the drill string 108. Thecomposition including the clay or shale stabilizer can also directly orindirectly affect any downhole heat exchangers, valves and correspondingactuation devices, tool seals, packers and other wellbore isolationdevices or components, and the like associated with the wellbore 116.The composition including the clay or shale stabilizer can also directlyor indirectly affect the drill bit 114, which can include roller conebits, polycrystalline diamond compact (PDC) bits, natural diamond bits,any hole openers, reamers, coring bits, and the like.

While not specifically illustrated herein, the composition including theclay or shale stabilizer can also directly or indirectly affect anytransport or delivery equipment used to convey the composition includingthe clay or shale stabilizer to the drilling assembly 100 such as, forexample, any transport vessels, conduits, pipelines, trucks, tubulars,and/or pipes used to fluidically move the composition including the clayor shale stabilizer from one location to another, any pumps,compressors, or motors used to drive the composition into motion, anyvalves or related joints used to regulate the pressure or flow rate ofthe composition, and any sensors (e.g., pressure and temperature),gauges, and/or combinations thereof, and the like.

System or Apparatus.

In various embodiments, the present invention provides a system. Thesystem can be any suitable system that can use or that can be generatedby use of an embodiment of the composition described herein in asubterranean formation, or that can perform or be generated byperformance of a method for using the composition described herein. Thesystem can include a composition including the clay or shale stabilizer.The system can also include a subterranean formation including thecomposition therein. In some embodiments, the composition in the systemcan also include a downhole fluid, or the system can include a mixtureof the composition and downhole fluid. In some embodiments, the systemcan include a tubular, and a pump configured to pump the compositioninto the subterranean formation through the tubular.

Various embodiments provide systems and apparatus configured fordelivering the composition described herein to a subterranean locationand for using the composition therein, such as for a drilling operation,a fracturing operation (e.g., pre-pad, pad, slurry, or finishingstages), a cementing operation, a completion operation, a loggingoperation, a spotting operation, or a packer operation. In variousembodiments, the system or apparatus can include a pump fluidly coupledto a tubular (e.g., any suitable type of oilfield pipe, such aspipeline, drill pipe, production tubing, and the like), with the tubularcontaining a composition including the clay or shale stabilizerdescribed herein.

In some embodiments, the system can include a drillstring disposed in awellbore, with the drillstring including a drill bit at a downhole endof the drillstring. The system can also include an annulus between thedrillstring and the wellbore. The system can also include a pumpconfigured to circulate the composition through the drill string,through the drill bit, and back above-surface through the annulus. Insome embodiments, the system can include a fluid processing unitconfigured to process the composition exiting the annulus to generate acleaned drilling fluid for recirculation through the wellbore.

In various embodiments, the present invention provides an apparatus. Theapparatus can be any suitable apparatus that can use the compositionincluding the clay or shale stabilizer described herein in asubterranean formation, or that can perform or be generated byperformance of a method for using the composition including the clay orshale stabilizer described herein.

The pump can be a high pressure pump in some embodiments. As usedherein, the term “high pressure pump” will refer to a pump that iscapable of delivering a fluid to a subterranean formation (e.g.,downhole) at a pressure of about 1000 psi or greater. A high pressurepump can be used when it is desired to introduce the composition to asubterranean formation at or above a fracture gradient of thesubterranean formation, but it can also be used in cases wherefracturing is not desired. In some embodiments, the high pressure pumpcan be capable of fluidly conveying particulate matter, such as proppantparticulates, into the subterranean formation. Suitable high pressurepumps will be known to one having ordinary skill in the art and caninclude floating piston pumps and positive displacement pumps.

In other embodiments, the pump can be a low pressure pump. As usedherein, the term “low pressure pump” will refer to a pump that operatesat a pressure of about 1000 psi or less. In some embodiments, a lowpressure pump can be fluidly coupled to a high pressure pump that isfluidly coupled to the tubular. That is, in such embodiments, the lowpressure pump can be configured to convey the composition to the highpressure pump. In such embodiments, the low pressure pump can “step up”the pressure of the composition before it reaches the high pressurepump.

In some embodiments, the systems or apparatuses described herein canfurther include a mixing tank that is upstream of the pump and in whichthe composition is formulated. In various embodiments, the pump (e.g., alow pressure pump, a high pressure pump, or a combination thereof) canconvey the composition from the mixing tank or other source of thecomposition to the tubular. In other embodiments, however, thecomposition can be formulated offsite and transported to a worksite, inwhich case the composition can be introduced to the tubular via the pumpdirectly from its shipping container (e.g., a truck, a railcar, a barge,or the like) or from a transport pipeline. In either case, thecomposition can be drawn into the pump, elevated to an appropriatepressure, and then introduced into the tubular for delivery to thesubterranean formation.

FIG. 2 shows an illustrative schematic of systems and apparatuses thatcan deliver embodiments of the compositions of the present invention toa subterranean location, according to one or more embodiments. It shouldbe noted that while FIG. 2 generally depicts a land-based system orapparatus, it is to be recognized that like systems and apparatuses canbe operated in subsea locations as well. Embodiments of the presentinvention can have a different scale than that depicted in FIG. 2. Asdepicted in FIG. 2, system or apparatus 1 can include mixing tank 10, inwhich an embodiment of the composition can be formulated. Thecomposition can be conveyed via line 12 to wellhead 14, where thecomposition enters tubular 16, with tubular 16 extending from wellhead14 into subterranean formation 18. Upon being ejected from tubular 16,the composition can subsequently penetrate into subterranean formation18. Pump 20 can be configured to raise the pressure of the compositionto a desired degree before its introduction into tubular 16. It is to berecognized that system or apparatus 1 is merely exemplary in nature andvarious additional components can be present that have not necessarilybeen depicted in FIG. 2 in the interest of clarity. In some examples,additional components that can be present include supply hoppers,valves, condensers, adapters, joints, gauges, sensors, compressors,pressure controllers, pressure sensors, flow rate controllers, flow ratesensors, temperature sensors, and the like.

Although not depicted in FIG. 2, at least part of the composition can,in some embodiments, flow back to wellhead 14 and exit subterraneanformation 18. The composition that flows back can be substantiallydiminished in the concentration of the clay or shale stabilizer, or canhave none of the clay or shale stabilizer therein. In some embodiments,the composition that has flowed back to wellhead 14 can subsequently berecovered, and in some examples reformulated, and recirculated tosubterranean formation 18.

It is also to be recognized that the disclosed composition can alsodirectly or indirectly affect the various downhole or subterraneanequipment and tools that can come into contact with the compositionduring operation. Such equipment and tools can include wellbore casing,wellbore liner, completion string, insert strings, drill string, coiledtubing, slickline, wireline, drill pipe, drill collars, mud motors,downhole motors and/or pumps, surface-mounted motors and/or pumps,centralizers, turbolizers, scratchers, floats (e.g., shoes, collars,valves, and the like), logging tools and related telemetry equipment,actuators (e.g., electromechanical devices, hydromechanical devices, andthe like), sliding sleeves, production sleeves, plugs, screens, filters,flow control devices (e.g., inflow control devices, autonomous inflowcontrol devices, outflow control devices, and the like), couplings(e.g., electro-hydraulic wet connect, dry connect, inductive coupler,and the like), control lines (e.g., electrical, fiber optic, hydraulic,and the like), surveillance lines, drill bits and reamers, sensors ordistributed sensors, downhole heat exchangers, valves and correspondingactuation devices, tool seals, packers, cement plugs, bridge plugs, andother wellbore isolation devices or components, and the like. Any ofthese components can be included in the systems and apparatusesgenerally described above and depicted in FIG. 2.

Composition for Treatment of a Subterranean Formation.

Various embodiments provide a composition for treatment of asubterranean formation. The composition can be any suitable compositionthat can be used to perform an embodiment of the method for treatment ofa subterranean formation described herein.

For example, the composition can include a clay or shale stabilizerincluding at least one of a substituted guanidine group and asubstituted guanidinium group. The composition can be or can include adownhole fluid, such as a drilling fluid, a fracturing fluid, acementing fluid, a completion fluid, a logging fluid, a spotting fluid,or a packer fluid. The clay or shale stabilizer can have the followingstructure:

The variable R⁷ can be selected from the group consisting of —OH, —OR⁸,—O⁻Y⁺, and —O⁻. The variable R⁸ can be a (C₁-C₅₀)hydrocarbyl. Thevariable Y⁺ is a counterion. The clay or shale stabilizer can be about0.001 wt % to about 10 wt % of the composition.Method for Preparing a Composition for Treatment of a SubterraneanFormation.

In various embodiments, the present invention provides a method forpreparing a composition for treatment of a subterranean formation. Themethod can be any suitable method that produces a composition describedherein. For example, the method can include forming a compositionincluding a clay or shale stabilizer including at least one of asubstituted guanidine group and a substituted guanidinium group.

The terms and expressions that have been employed are used as terms ofdescription and not of limitation, and there is no intention in the useof such terms and expressions of excluding any equivalents of thefeatures shown and described or portions thereof, but it is recognizedthat various modifications are possible within the scope of theembodiments of the present invention. Thus, it should be understood thatalthough the present invention has been specifically disclosed byspecific embodiments and optional features, modification and variationof the concepts herein disclosed may be resorted to by those of ordinaryskill in the art, and that such modifications and variations areconsidered to be within the scope of embodiments of the presentinvention.

Additional Embodiments

The following exemplary embodiments are provided, the numbering of whichis not to be construed as designating levels of importance:

Embodiment 1 provides a method of treating a subterranean formation, themethod comprising:

-   -   placing a composition comprising a clay or shale stabilizer        comprising at least one of a substituted guanidine group and a        substituted guanidinium group in a subterranean formation.

Embodiment 2 provides the method of Embodiment 1, wherein the methodfurther comprises obtaining or providing the composition, wherein theobtaining or providing of the composition occurs above-surface.

Embodiment 3 provides the method of any one of Embodiments 1-2, whereinthe method further comprises obtaining or providing the composition,wherein the obtaining or providing of the composition occurs in thesubterranean formation.

Embodiment 4 provides the method of any one of Embodiments 1-3, whereinthe composition is at least one of a drilling fluid, fracturing fluid,cementing fluid, completion fluid, logging fluid, spotting fluid, and apacker fluid, or wherein the composition comprises at least one of adrilling fluid, fracturing fluid, cementing fluid, completion fluid,logging fluid, spotting fluid, and a packer fluid.

Embodiment 5 provides the method of any one of Embodiments 1-4, whereinthe composition is oil- or water-based.

Embodiment 6 provides the method of any one of Embodiments 1-5, whereinthe composition is a water- or oil-based emulsion.

Embodiment 7 provides the method of Embodiment 6, wherein the claystabilizer is at least partially dissolved in the water- or oil-phase ofthe emulsion.

Embodiment 8 provides the method of any one of Embodiments 1-7, whereinthe composition comprises a carrier fluid.

Embodiment 9 provides the method of Embodiment 8, wherein the carrierfluid is about 0.001 wt % to about 99.999 wt % of the composition.

Embodiment 10 provides the method of any one of Embodiments 8-9, whereinthe carrier fluid is about 50 wt % to about 99.999 wt % of thecomposition.

Embodiment 11 provides the method of any one of Embodiments 1-10,wherein about 0.000.1 wt % to about 99.999 wt % of the composition isthe clay or shale stabilizer.

Embodiment 12 provides the method of any one of Embodiments 1-11,wherein about 0.001 wt % to about 10 wt % of the composition is the clayor shale stabilizer.

Embodiment 13 provides the method of any one of Embodiments 1-12,wherein the clay or shale stabilizer has the structure:

-   -   wherein        -   R¹, R², R³, R⁴, R⁵, and R⁶ are each independently selected            from —H, halogen, an organic group, and substituted or            unsubstituted (C₁-C₃₀)hydrocarbyl interrupted by 0, 1, 2, or            3 of at least one of —O—, —S—, and substituted or            unsubstituted —NH—, or at least one pair of R¹, R², R³, R⁴,            R⁵, and R⁶ together form a substituted or unsubstituted            (C₂-C₂₀)hydrocarbylene such that at least two of the            nitrogen atoms in the clay or shale stabilizer are part of a            heterocycle including the substituted or unsubstituted            (C₂-C₂₀)hydrocarbylene, wherein optionally at least one of            R¹, R², R³, R⁴, R⁵, and R⁶ is bonded to at least one R¹, R²,            R³, R⁴, R⁵, and R⁶ on a different guanidine or guanidinium            group in the same clay or shale stabilizer,        -   at least one of R¹, R², R³, R⁴, and R⁵ is not —H, and        -   X⁻ is a counterion.

Embodiment 14 provides the method of Embodiment 13, wherein the clay orshale stabilizer has the structure:

Embodiment 15 provides the method of any one of Embodiments 13-14,wherein R⁶ is H.

Embodiment 16 provides the method of any one of Embodiments 13-15,wherein X⁻ is selected from the group consisting of fluoro, chloro,iodo, bromo, nitrate, hydrogen sulfate, dihydrogen phosphate,bicarbonate, nitrite, perchlorate, iodate, chlorate, bromate, chlorite,hypochlorite, hypobromite, cyanide, amide, cyanate, hydroxide,permanganate, acetate, formate, oxide, sulfide, nitride, arsenate,phosphate, arsenite, hydrogen phosphate, sulfate, thiosulfate, sulfite,carbonate, chromate, dichromate, peroxide, and oxalate.

Embodiment 17 provides the method of any one of Embodiments 13-16,wherein R², R³, R⁴, R⁵, and R⁶ are each independently selected from —Hand substituted or unsubstituted (C₁-C₁₅)alkyl.

Embodiment 18 provides the method of any one of Embodiments 13-17,wherein R², R³, R⁴, R⁵, and R⁶ are each independently selected from —Hand substituted or unsubstituted (C₁-C₅)alkyl.

Embodiment 19 provides the method of any one of Embodiments 13-18,wherein R², R³, R⁴, R⁵, and R⁶ are each —H.

Embodiment 20 provides the method of any one of Embodiments 13-19,wherein at least one pair of R¹, R², R³, R⁴, R⁵, and R⁶ together form a(C₂-C₅)alkylene such that at least two of the nitrogen atoms in the clayor shale stabilizer are part of a heterocycle including the(C₂-C₅)alkylene.

Embodiment 21 provides the method of any one of Embodiments 13-20,wherein at least one pair of R¹, R², R³, R⁴, R⁵, and R⁶ together form a(C₃)alkylene such that at least two of the nitrogen atoms in the clay orshale stabilizer are part of a heterocycle including the (C₃)alkylene.

Embodiment 22 provides the method of any one of Embodiments 13-21,wherein the clay or shale stabilizer is1,5,7-triazabicyclo[4.4.0]dec-5-ene, having the structure:

Embodiment 23 provides the method of any one of Embodiments 13-22,wherein the clay or shale stabilizer is a polymer.

Embodiment 24 provides the method of Embodiment 23, wherein thesubstituted guanidine group or substituted guanidinium group are pendantgroups on the polymer.

Embodiment 25 provides the method of any one of Embodiments 23-24,wherein at least one of R¹, R², R³, R⁴, R⁵, and R⁶ is bonded to at leastone R¹, R², R³, R⁴, R⁵, and R⁶ on a different guanidine or guanidiniumgroup in the same clay or shale stabilizer.

Embodiment 26 provides the method of any one of Embodiments 1-25,wherein the clay or shale stabilizer comprises two or more of theguanidine or guanidinium groups connected to one another via a(C₁-C₃₀)hydrocarbyl linker.

Embodiment 27 provides the method of any one of Embodiments 13-26,wherein the clay or shale stabilizer has the structure:

-   -   wherein        -   R², R³, R⁴, R⁵, and R⁶ are each independently selected from            —H, halogen, an organic group, and substituted or            unsubstituted (C₁-C₃₀)hydrocarbyl interrupted by 0, 1, 2, or            3 of at least one of —O—, —S—, and substituted or            unsubstituted —NH—, or at least one pair of R², R³, R⁴, R⁵,            and R⁶ together form a substituted or unsubstituted            (C₂-C₂₀)hydrocarbylene such that at least two of the            nitrogen atoms in the clay or shale stabilizer are part of a            heterocycle including the substituted or unsubstituted            (C₂-C₂₀)hydrocarbylene, wherein optionally at least one of            R², R³, R⁴, R⁵, and R⁶ is bonded to at least one R², R³, R⁴,            R⁵, and R⁶ on a different guanidine or guanidinium group in            the same clay or shale stabilizer,        -   L³ is a substituted or unsubstituted (C₁-C₃₀)hydrocarbyl            interrupted by 0, 1, 2, or 3 of at least one of —O—, —S—,            and substituted or unsubstituted —NH—, and        -   X⁻ is a counterion.

Embodiment 28 provides the method of Embodiment 27, wherein L³ is(C₂-C₂₀)alkyl.

Embodiment 29 provides the method of any one of Embodiments 27-28,wherein the clay or shale stabilizer is 1,6-hexamethylene-bis-guanidineor 1,6-hexamethylene-bis-cyanoguanidine.

Embodiment 30 provides the method of any one of Embodiments 13-29,whereinR¹ is -L¹-C(O)R⁷,

-   -   L¹ is selected from the group consisting of a bond, a        substituted or unsubstituted (C₁-C₃₀)hydrocarbylene interrupted        by 0, 1, 2, or 3 of at least one of —O—, —S—, and substituted or        unsubstituted —NH—, wherein L¹ optionally comprises a bond to at        least one R¹, R², R³, R⁴, R⁵, and R⁶ on a different guanidine or        guanidinium group in the same clay or shale stabilizer,    -   R⁷ is selected from the group consisting of —OH, —OR⁸, —O—Y⁺,        —O—, and a bond to at least one R¹, R², R³, R⁴, R⁵, and R⁶ on a        different guanidine or guanidinium group in the same clay or        shale stabilizer,    -   R⁸ is a substituted or unsubstituted (C₁-C₅₀)hydrocarbyl        interrupted by 0, 1, 2, or 3 of at least one of —O—, —S—, and        substituted or unsubstituted —NH—, and    -   Y⁺ is a counterion.

Embodiment 31 provides the method of Embodiment 30, wherein L¹ is a(C₁-C₃₀)hydrocarbylene interrupted by 0, 1, 2, or 3 of at least one of—O—, —S—, and substituted or unsubstituted —NH—, and comprising at leastone —NH₂ substituent.

Embodiment 32 provides the method of any one of Embodiments 30-31,wherein L¹ is a (C₁-C₁₅)alkylene comprising at least one —NH₂substituent.

Embodiment 33 provides the method of any one of Embodiments 30-32,wherein L¹ is a butylene comprising at least one —NH₂ substituent.

Embodiment 34 provides the method of Embodiment 33, wherein L¹ is—(CH₂)₃—CH(NH₂)—.

Embodiment 35 provides the method of any one of Embodiments 30-34,wherein R⁸ is a (C₁-C₅₀)alkyl.

Embodiment 36 provides the method of any one of Embodiments 30-35,wherein R⁸ is a (C₁-C₁₅)alkyl.

Embodiment 37 provides the method of any one of Embodiments 30-36,wherein R⁸ is a (C₁-C₅)alkyl.

Embodiment 38 provides the method of any one of Embodiments 30-37,wherein R⁸ is ethyl.

Embodiment 39 provides the method of any one of Embodiments 30-38,wherein Y⁺ is selected from the group consisting of Na⁺, K⁺, Li⁺, H⁺,NH₄, Ca²⁺, Mg²⁺, Zn²⁺, and Al³⁺.

Embodiment 40 provides the method of any one of Embodiments 30-39,wherein the clay or shale stabilizer has the structure:

Embodiment 41 provides the method of any one of Embodiments 30-40,wherein the clay or shale stabilizer is a polymer comprising repeatingunits having the structure:

Embodiment 42 provides the method of any one of Embodiments 30-41,wherein the clay or shale stabilizer has the structure:

-   -   wherein    -   L² is selected from the group consisting of a bond and a        substituted or unsubstituted (C₁-C₂₈)hydrocarbylene interrupted        by 0, 1, 2, or 3 of at least one of —O—, —S—, and substituted or        unsubstituted —NH—.

Embodiment 43 provides the method of any one of Embodiments 30-42,wherein the clay or shale stabilizer is a polymer comprising repeatingunits having the structure:

Embodiment 44 provides the method of any one of Embodiments 42-43,wherein L² is a (C₁-C₁₅)alkylene.

Embodiment 45 provides the method of any one of Embodiments 42-44,wherein L² is propylene.

Embodiment 46 provides the method of any one of Embodiments 42-45,wherein L² is —(CH₂)₃—.

Embodiment 47 provides the method of any one of Embodiments 13-46,wherein the clay or shale stabilizer has the structure:

or a salt thereof,

or a salt thereof, or

Embodiment 48 provides the method of any one of Embodiments 13-47,wherein the clay or shale stabilizer is a polymer comprising repeatingunits having the structure:

Embodiment 49 provides the method of any one of Embodiments 1-48,wherein the clay or shale stabilizer has the structure:

or a salt thereof,

or a salt thereof, or

Embodiment 50 provides the method of any one of Embodiments 1-49,wherein the clay or shale stabilizer is a polymer comprising repeatingunits having the structure:

Embodiment 51 provides the method of any one of Embodiments 1-50,wherein the clay or shale stabilizer has the structure:

or a salt thereof,

or a salt thereof,

Embodiment 52 provides the method of any one of Embodiments 1-51,wherein the clay or shale stabilizer is a polymer comprising repeatingunits having the structure:

Embodiment 53 provides the method of any one of Embodiments 30-52,wherein the clay or shale stabilizer has the structure:

Embodiment 54 provides the method of Embodiment 53, wherein R⁸ is(C₁-C₅)alkyl.

Embodiment 55 provides the method of any one of Embodiments 53-54,wherein R⁸ is ethyl.

Embodiment 56 provides the method of any one of Embodiments 30-55,wherein the clay or shale stabilizer has the structure:

Embodiment 57 provides the method of Embodiment 56, wherein R⁸ is(C₁-C₅)alkyl.

Embodiment 58 provides the method of any one of Embodiments 56-57,wherein R⁸ is ethyl.

Embodiment 59 provides the method of any one of Embodiments 1-58,wherein the composition comprises one or more second clay or shalestabilizers.

Embodiment 60 provides the method of Embodiment 59, wherein the secondclay or shale stabilizer is at least one of a substituted orunsubstituted amine, potassium chloride, a crosslinkedpolyvinylpyrrolidone, an inorganic phosphate, a polyalkoxy diamine or asalt thereof, choline or a choline derivative, an oligomethylene diamineor a salt thereof, an addition product of carboxymethyl cellulose and anorganic amine, 1,2-cyclohexanediamine or a salt thereof, a salt of aphosphoric acid ester of an oxyalkylated polyol, a combination of apartially hydrolyzed acrylic copolymer potassium chloride andpolyanionic cellulose, a quaternary ammonium compound, a polymer basedon dialkyl aminoalkyl methacrylate, an aqueous solution containing apolymer with hydrophilic and hydrophobic groups, and a reaction productof a polyhydroxyalkane and an alkylene oxide.

Embodiment 61 provides the method of any one of Embodiments 1-60,wherein the composition further comprises a viscosifier.

Embodiment 62 provides the method of Embodiment 61, wherein theviscosifier is crosslinked or uncrosslinked.

Embodiment 63 provides the method of any one of Embodiments 61-62,wherein the viscosifier comprises at least one of a linearpolysaccharide, and a polymer of a (C₂-C₅₀)hydrocarbyl having at leastone carbon-carbon unsaturated aliphatic bond therein, wherein the(C₂-C₅₀)hydrocarbyl is substituted or unsubstituted.

Embodiment 64 provides the method of any one of Embodiments 1-63,wherein the composition further comprises a crosslinker.

Embodiment 65 provides the method of Embodiment 64, wherein thecrosslinker comprises at least one of chromium, aluminum, antimony,zirconium, titanium, calcium, boron, iron, silicon, copper, zinc,magnesium, and an ion thereof.

Embodiment 66 provides the method of any one of Embodiments 64-65,wherein the crosslinker comprises at least one of boric acid, borax, aborate, a (C₁-C₃₀)hydrocarbylboronic acid, a (C₁-C₃₀)hydrocarbyl esterof a (C₁-C₃₀)hydrocarbylboronic acid, a (C₁-C₃₀)hydrocarbylboronicacid-modified polyacrylamide, ferric chloride, disodium octaboratetetrahydrate, sodium metaborate, sodium diborate, sodium tetraborate,disodium tetraborate, a pentaborate, ulexite, colemanite, magnesiumoxide, zirconium lactate, zirconium triethanol amine, zirconium lactatetriethanolamine, zirconium carbonate, zirconium acetylacetonate,zirconium malate, zirconium citrate, zirconium diisopropylamine lactate,zirconium glycolate, zirconium triethanol amine glycolate, zirconiumlactate glycolate, titanium lactate, titanium malate, titanium citrate,titanium ammonium lactate, titanium triethanolamine, titaniumacetylacetonate, aluminum lactate, and aluminum citrate.

Embodiment 67 provides the method of any one of Embodiments 64-66,wherein the crosslinker comprises at least one of a(C₁-C₂₀)alkylenebiacrylamide, a poly((C₁-C₂₀)alkenyl)-substituted mono-or poly-(C₁-C₂₀)alkyl ether, a poly(C₂-C₂₀)alkenylbenzene, alkyldiacrylate, ethylene glycol diacrylate, ethylene glycol dimethacrylate,polyethylene glycol diacrylate, polyethylene glycol dimethacrylate,ethoxylated bisphenol A diacrylate, ethoxylated bisphenol Adimethacrylate, ethoxylated trimethylol propane triacrylate, ethoxylatedtrimethylol propane trimethacrylate, ethoxylated glyceryl triacrylate,ethoxylated glyceryl trimethacrylate, ethoxylated pentaerythritoltetraacrylate, ethoxylated pentaerythritol tetramethacrylate,ethoxylated dipentaerythritol hexaacrylate, polyglyceryl monoethyleneoxide polyacrylate, polyglyceryl polyethylene glycol polyacrylate,dipentaerythritol hexaacrylate, dipentaerythritol hexamethacrylate,neopentyl glycol diacrylate, neopentyl glycol dimethacrylate,pentaerythritol triacrylate, pentaerythritol trimethacrylate,trimethylol propane triacrylate, trimethylol propane trimethacrylate,tricyclodecane dimethanol diacrylate, tricyclodecane dimethanoldimethacrylate, 1,6-hexanediol diacrylate, and 1,6-hexanedioldimethacrylate.

Embodiment 68 provides the method of any one of Embodiments 1-67,further comprising combining the composition with an aqueous oroil-based fluid comprising a drilling fluid, stimulation fluid,fracturing fluid, spotting fluid, clean-up fluid, completion fluid,remedial treatment fluid, abandonment fluid, pill, acidizing fluid,cementing fluid, packer fluid, logging fluid, or a combination thereof,to form a mixture, wherein the placing the composition in thesubterranean formation comprises placing the mixture in the subterraneanformation.

Embodiment 69 provides the method of Embodiment 68, wherein thecementing fluid comprises Portland cement, pozzolana cement, gypsumcement, high alumina content cement, slag cement, silica cement, or acombination thereof.

Embodiment 70 provides the method of any one of Embodiments 1-69,wherein at least one of prior to, during, and after the placing of thecomposition in the subterranean formation, the composition is used inthe subterranean formation, at least one of alone and in combinationwith other materials, as a drilling fluid, stimulation fluid, fracturingfluid, spotting fluid, clean-up fluid, completion fluid, remedialtreatment fluid, abandonment fluid, pill, acidizing fluid, cementingfluid, packer fluid, logging fluid, or a combination thereof.

Embodiment 71 provides the method of any one of Embodiments 1-70,wherein the composition further comprises water, saline, aqueous base,oil, organic solvent, synthetic fluid oil phase, aqueous solution,alcohol or polyol, cellulose, starch, alkalinity control agent, aciditycontrol agent, density control agent, density modifier, emulsifier,dispersant, polymeric stabilizer, crosslinking agent, polyacrylamide,polymer or combination of polymers, antioxidant, heat stabilizer, foamcontrol agent, solvent, diluent, plasticizer, filler or inorganicparticle, pigment, dye, precipitating agent, rheology modifier,oil-wetting agent, set retarding additive, surfactant, corrosioninhibitor, gas, weight reducing additive, heavy-weight additive, lostcirculation material, filtration control additive, salt, fiber,thixotropic additive, breaker, crosslinker, gas, rheology modifier,curing accelerator, curing retarder, pH modifier, chelating agent, scaleinhibitor, enzyme, resin, water control material, polymer, oxidizer, amarker, Portland cement, pozzolana cement, gypsum cement, high aluminacontent cement, slag cement, silica cement, fly ash, metakaolin, shale,zeolite, a crystalline silica compound, amorphous silica, fibers, ahydratable clay, microspheres, pozzolan lime, or a combination thereof.

Embodiment 72 provides the method of any one of Embodiments 1-71,wherein the placing of the composition in the subterranean formationcomprises fracturing at least part of the subterranean formation to format least one subterranean fracture.

Embodiment 73 provides the method of any one of Embodiments 1-72,wherein the composition further comprises a proppant, a resin-coatedproppant, or a combination thereof.

Embodiment 74 provides the method of any one of Embodiments 1-73,wherein the placing of the composition in the subterranean formationcomprises pumping the composition through a drill string disposed in awellbore, through a drill bit at a downhole end of the drill string, andback above-surface through an annulus.

Embodiment 75 provides the method of Embodiment 74, further comprisingprocessing the composition exiting the annulus with at least one fluidprocessing unit to generate a cleaned composition and recirculating thecleaned composition through the wellbore.

Embodiment 76 provides a system for performing the method of any one ofEmbodiments 1-75, the system comprising:

-   -   a tubular disposed in the subterranean formation; and    -   a pump configured to pump the composition in the subterranean        formation through the tubular.

Embodiment 77 provides a system for performing the method of any one ofEmbodiments 1-75, the system comprising:

-   -   a drillstring disposed in a wellbore, the drillstring comprising        a drill bit at a downhole end of the drillstring;    -   an annulus between the drillstring and the wellbore; and    -   a pump configured to circulate the composition through the drill        string, through the drill bit, and back above-surface through        the annulus.

Embodiment 78 provides a method of treating a subterranean formation,the method comprising:

-   -   placing in a subterranean formation a drilling fluid, fracturing        fluid, cementing fluid, completion fluid, logging fluid,        spotting fluid, or a packer fluid comprising a clay or shale        stabilizer having the following structure

-   -   wherein        -   R⁷ is selected from the group consisting of —OH, —OR⁸,            —[O]Y⁺, and —O⁻,        -   R⁸ is a (C₁-C₅₀)hydrocarbyl,        -   Y⁺ is a counterion, and        -   the clay or shale stabilizer is about 0.001 wt % to about 10            wt % of the drilling fluid, fracturing fluid, or cementing            fluid.

Embodiment 79 provides a method of treating a subterranean formation,the method comprising:

-   -   placing a composition comprising a clay or shale stabilizer in a        subterranean formation, the clay or shale stabilizer comprising        at least one of an unsubstituted guanidine and an unsubstituted        guanidinium, wherein the guanidine and guanidinium are free of        complexation with polyvalent metals.

Embodiment 80 provides the method of Embodiment 79, wherein theguanidine and guanidinium are free of complexation with metals.

Embodiment 81 provides a system comprising:

-   -   a composition comprising a clay or shale stabilizer comprising        at least one of a substituted guanidine group and a substituted        guanidinium group; and    -   a subterranean formation comprising the composition therein.

Embodiment 82 provides the system of Embodiment 81, further comprising

-   -   a drillstring disposed in a wellbore, the drillstring comprising        a drill bit at a downhole end of the drillstring;    -   an annulus between the drillstring and the wellbore; and    -   a pump configured to circulate the composition through the drill        string, through the drill bit, and back above-surface through        the annulus.

Embodiment 83 provides the system of Embodiment 82, further comprising afluid processing unit configured to process the composition exiting theannulus to generate a cleaned drilling fluid for recirculation throughthe wellbore.

Embodiment 84 provides the system of any one of Embodiments 81-83,further comprising

-   -   a tubular disposed in the subterranean formation; and    -   a pump configured to pump the composition in the subterranean        formation through the tubular.

Embodiment 85 provides a composition for treatment of a subterraneanformation, the composition comprising:

-   -   a clay or shale stabilizer comprising at least one of a        substituted guanidine group and a substituted guanidinium group.

Embodiment 86 provides the composition of Embodiment 85, wherein thecomposition is at least one of a drilling fluid, fracturing fluid,cementing fluid, completion fluid, logging fluid, spotting fluid, and apacker fluid.

Embodiment 87 provides a drilling fluid, fracturing fluid, cementingfluid, completion fluid, logging fluid, spotting fluid, or a packerfluid for treatment of a subterranean formation, the compositioncomprising:

-   -   a clay or shale stabilizer having the following structure

-   -   wherein        -   R⁷ is selected from the group consisting of —OH, —OR⁸,            —[O⁻]Y⁺, and —O⁻,        -   R⁸ is a (C₁-C₅₀)hydrocarbyl,        -   Y⁺ is a counterion, and        -   the clay or shale stabilizer is about 0.001 wt % to about 10            wt % of the drilling fluid, fracturing fluid, cementing            fluid, completion fluid, logging fluid, spotting fluid, or            the packer fluid.

Embodiment 88 provides a method of preparing a composition for treatmentof a subterranean formation, the method comprising:

-   -   forming a composition comprising        -   a clay or shale stabilizer comprising at least one of a            substituted guanidine group and a substituted guanidinium            group.

Embodiment 88 provides the composition, method, or system of any one orany combination of Embodiments 1-87 optionally configured such that allelements or options recited are available to use or select from.

What is claimed is:
 1. A system comprising: a tubular disposed in asubterranean formation; a composition comprising a clay or shalestabilizer comprising at least one of the following structures:

wherein the variable R⁸ is a (C₂-C₅) alkyl group; and a pump configuredto pump the composition in the subterranean formation through thetubular.
 2. The system of claim 1 further comprising: a drillstringdisposed in a wellbore, the drillstring comprising a drill bit at adownhole end of the drillstring; an annulus between the drillstring andthe wellbore; and a pump configured to circulate the composition throughthe drill string, through the drill bit, and back above-surface throughthe annulus.
 3. The system of claim 1, wherein the system is configuredfor delivering the composition for at least one of a drilling operation,fracturing operation, cementing operation, completion operation, loggingoperation, spotting operation, and a packer operation.
 4. The system ofclaim 1, wherein the composition is oil- or water-based or wherein thecomposition is a water- or oil-based emulsion.
 5. The system of claim 1,wherein the clay or shale stabilizer further comprises at least one ofthe following structures:

wherein R¹, R², R³, R⁴, R⁵, and R⁶ are each independently selected from—H, halogen, an organic group, and substituted or unsubstituted(C₁-C₃₀)hydrocarbyl interrupted by 0, 1, 2, or 3 of at least one of —O—,—S—, and substituted or unsubstituted —NH—, or at least one pair of R¹,R², R³, R⁴, R⁵, and R⁶ together form a substituted or unsubstituted(C₂-C₂₀)hydrocarbylene such that at least two of the nitrogen atoms inthe clay or shale stabilizer are part of a heterocycle including thesubstituted or unsubstituted (C₂-C₂₀)hydrocarbylene, wherein optionallyat least one of R¹, R², R³, R⁴, R⁵, and R⁶ is bonded to at least one R¹,R², R³, R⁴, R⁵, and R⁶ on a different guanidine or guanidinium group inthe same clay or shale stabilizer, at least one of R¹, R², R³, R⁴, andR⁵ is not —H, and X⁻ is a counterion.
 6. The system of claim 5, whereinX⁻ is selected from the group consisting of fluoro, chloro, iodo, bromo,nitrate, hydrogen sulfate, dihydrogen phosphate, bicarbonate, nitrite,perchlorate, iodate, chlorate, bromate, chlorite, hypochlorite,hypobromite, cyanide, amide, cyanate, hydroxide, permanganate, acetate,formate, oxide, sulfide, nitride, arsenate, phosphate, arsenite,hydrogen phosphate, sulfate, thiosulfate, sulfite, carbonate, chromate,dichromate, peroxide, and oxalate.
 7. The system of claim 1, wherein theclay or shale stabilizer further comprises1,5,7-triazabicyclo[4.4.0]dec-5-ene, having the structure:


8. The system of claim 1, wherein the clay or shale stabilizer furthercomprises:

wherein R², R³, R⁴, R⁵, and R⁶ are each independently selected from —H,halogen, an organic group, and substituted or unsubstituted(C₁-C₃₀)hydrocarbyl interrupted by 0, 1, 2, or 3 of at least one of —O—,—S—, and substituted or unsubstituted —NH—, or at least one pair of R²,R³, R⁴, R⁵, and R⁶ together form a substituted or unsubstituted(C₂-C₂₀)hydrocarbylene such that at least two of the nitrogen atoms inthe clay or shale stabilizer are part of a heterocycle including thesubstituted or unsubstituted (C₂-C₂₀)hydrocarbylene, wherein optionallyat least one of R², R³, R⁴, R⁵, and R⁶ is bonded to at least one R², R³,R⁴, R⁵, and R⁶ on a different guanidine or guanidinium group in the sameclay or shale stabilizer, L³ is a substituted or unsubstituted(C₁-C₃₀)hydrocarbyl interrupted by 0, 1, 2, or 3 of at least one of —O—,—S—, and substituted or unsubstituted —NH—, and X⁻ is a counterion. 9.The system of claim 8, wherein L³ is (C₂-C₂₀)alkyl.
 10. The system ofclaim 8, wherein R¹ is -L¹-C(O)R⁷, L¹ is selected from the groupconsisting of a bond, a substituted or unsubstituted(C₁-C₃₀)hydrocarbylene interrupted by 0, 1, 2, or 3 of at least one of—O—, —S—, and substituted or unsubstituted —NH—, wherein L¹ optionallycomprises a bond to at least one R¹, R², R³, R⁴, R⁵, and R⁶ on adifferent guanidine or guanidinium group in the same clay or shalestabilizer, R⁷ is selected from the group consisting of —OH, —OR⁸,—O⁻Y⁺, —O⁻, and a bond to at least one R¹, R², R³, R⁴, R⁵, and R⁶ on adifferent guanidine or guanidinium group in the same clay or shalestabilizer, R⁸ is a substituted or unsubstituted (C₁-C₅₀)hydrocarbylinterrupted by 0, 1, 2, or 3 of at least one of —O—, —S—, andsubstituted or unsubstituted —NH—, and Y⁺ is a counterion.
 11. Thesystem of claim 10, wherein Y⁺ is selected from the group consisting ofNa⁺, K⁺, Li⁺, H⁺, NH₄ ⁺, Ca²⁺, Mg²⁺, Zn²⁺, and Al³⁺.
 12. The system ofclaim 1, wherein the clay or shale stabilizer further comprises1,6-hexamethylene-bis-guanidine or 1,6-hexamethylene-bis-cyanoguanidine.13. The system of claim 1, wherein the clay or shale stabilizer furthercomprises at least one of the following structures:


14. The system of claim 1, wherein the clay or shale stabilizer furthercomprises a polymer comprising repeating units having the structure:


15. The system of claim 1, wherein the clay or shale stabilizer furthercomprises at least one of the following structures:

wherein L² is selected from the group consisting of a bond and asubstituted or unsubstituted (C₁-C₂₈)hydrocarbylene interrupted by 0, 1,2, or 3 of at least one of —O—, —S—, and substituted or unsubstituted—NH—.
 16. The system of claim 1, wherein the clay or shale stabilizerfurther comprises a polymer comprising repeating units having thestructure:


17. The system of claim 1 wherein clay or shale stabilizer is asubstituted arginine with at least one of the following structures:

wherein the variable R⁸ is ethyl.
 18. A method of treating asubterranean formation, the method comprising: preparing a treatmentfluid comprising: a base fluid, and a clay or shale stabilizercomprising:

wherein the variable R⁸ is a (C₂-C₅) alkyl group, and at least one of:a. 1,5,7-triazabicyclo[4.4.0]dec-5-ene, having the structure:

b. 1,6-hexamethylene-bis-guanidine; c.1,6-hexamethylene-bis-cyanoguanidine; d. arginine, substituted arginine,or any salt thereof; or e. polyarginine; and placing the treatment fluidinto a subterranean formation.